2018 eai integrated resource plan - entergy arkansas...october 31, 2018 ms. mary loos arkansas...

October 31, 2018

Ms. Mary LoosArkansas Public Service CommissionP. O. Box 4001000 Center StreetLittle Rock, AR 72203

Re: APSC Docket No. 07-016-UEntergy Arkansas, Inc. 2018 Integrated Resource Plan

Dear Ms. Loos:

Consistent with Section 6 of Attachment 1 to the Arkansas Public ServiceCommission (“Commission”) Order No. 6 – Docket No. 06-028-R ResourcePlanning Guidelines for Electric Utilities, Entergy Arkansas, Inc. (“EAI”) submitsits 2018 Integrated Resource Plan and the Stakeholder Report that was preparedin accordance with Section 4.8 of the Commission’s Resource PlanningGuidelines.

Should you have any questions concerning this filing, please call me at (501)377-3571 or Jeff McGee at (501) 377-3976.

Sincerely,

/s/ J. David Palmer

DPAttachments

c: All Parties of Record

Entergy Arkansas, Inc.425 West Capitol AvenueP. O. Box 551Little Rock, AR 72203-0551Tel 501 377 3571Fax 501 377 3599

J. David PalmerDirector, Regulatory Affairs

APSC FILED Time: 10/31/2018 1:48:40 PM: Recvd 10/31/2018 1:47:12 PM: Docket 07-016-U-Doc. 60

Entergy Arkansas, Inc.2018 Integrated Resource Plan

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http://www.entergy-arkansas.com/integrated_resource_planning

http://www.entergy-arkansas.com/rfp/energy_capacity.aspx

http://www.icf.com/

https://www.nrel.gov/docs/fy16osti/65023.pdf

https://cdn.misoenergy.org/20180605%20RIIA%20Workshop%20Presentation213125.pdf

[This Page Intentionally Left Blank]

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http://www.entergy-arkansas.com/integrated_resource_planning

2018 EAI Integrated Resource Plan

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TABLE OF CONTENTS

List of Tables .............................................................................................................................................................................. 5

List of Figures............................................................................................................................................................................. 5

Abbreviations & Definitions .............................................................................................................................................. 7

Executive Summary ...................................................................................................................................................................... 8

I. Integrated Resource Plan Background and Context .................................................................................. 10

1. Introduction .................................................................................................................................................................... 10

2. Resource Planning Objectives.......................................................................................................................... 10

3. Regulatory Context for EAI’s IRP ................................................................................................................... 11

4. The 2015 IRP Action Plan .................................................................................................................................. 12

II. EAI Resource Planning ...................................................................................................................................................... 14

1. Existing Resources .................................................................................................................................................... 14

2. Planned Resources ................................................................................................................................................... 16

3. Future of Existing Resources ............................................................................................................................ 17

4. Resource Needs.......................................................................................................................................................... 18

5. Transmission Planning ........................................................................................................................................... 20

6. Distribution Planning ............................................................................................................................................... 22

III. The 2018 Integrated Resource Plan .................................................................................................................... 24

1. Key Inputs and Assumptions Overview .................................................................................................... 24

1.1 Changing Utility ........................................................................................................................................................ 24

2. Sales and Load Forecasts ................................................................................................................................. 26

2.1 Arkansas Economic Outlook .......................................................................................................................... 30

2.2 Demand-side Management .............................................................................................................................. 31

3. Capacity Resource Options ............................................................................................................................... 34

3.1 Generation Technology Assessment ........................................................................................................ 34

3.2 Energy Storage Systems ................................................................................................................................... 39

3.3 Potential DSM Resource Assessment ...................................................................................................... 41

4. Environmental ............................................................................................................................................................... 42

5. Fuel Price Forecasts ................................................................................................................................................ 45

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5.1 Natural Gas Price Forecasts .......................................................................................................................... 45

5.2 Coal Price Forecasts............................................................................................................................................ 46

5.3 CO2 Price Forecasts ............................................................................................................................................. 46

6. Modeling Framework ............................................................................................................................................... 47

6.1 Futures-based Approach ................................................................................................................................... 47

6.2 IRP Modeling Overview ....................................................................................................................................... 51

6.3 Market Modeling ...................................................................................................................................................... 51

6.4 EAI Portfolio Optimization ................................................................................................................................ 52

6.5 2018 EAI IRP DSM Modeling .......................................................................................................................... 53

7. Results ................................................................................................................................................................................ 55

7.1 Future A Results ...................................................................................................................................................... 55

7.2 Future B Results ...................................................................................................................................................... 57

7.3 Future C Results ..................................................................................................................................................... 58

7.4 Future A Sensitivity Results ............................................................................................................................ 61

7.5 Future B Sensitivity Results ............................................................................................................................ 63

7.6 Future C Sensitivity Results ............................................................................................................................ 65

IV. Action Plan .............................................................................................................................................................................. 67

1. Findings and Conclusions ................................................................................................................................... 67

1.1 Summary of Findings ........................................................................................................................................... 67

2. Action Plan ..................................................................................................................................................................... 68

2018 IRP Action Plan .................................................................................................................................................... 69

V. Stakeholder Engagement ............................................................................................................................................... 71

Appendix A – Resource Planning Objectives ........................................................................................................ 73

Appendix B - EAI Portfolio of Resources ................................................................................................................ 75

Appendix C - MISO MTEP Submissions .................................................................................................................... 77

Appendix D – Scope of AURORA Market Model ............................................................................................... 80

Appendix E – Stakeholder Report ................................................................................................................................. 81

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LIST OF TABLES

Table 1: 2018 IRP Technology Categories ............................................................................................................ 35Table 2: Gas-Fired Technology Considerations ................................................................................................. 35Table 3: Gas-Fired Resource Assumptions ............................................................................................................ 36Table 4: Renewable Technology Considerations ............................................................................................... 37Table 5: Additional Benefits of Renewables ......................................................................................................... 38Table 6: Renewable Modeling Assumptions .......................................................................................................... 39Table 7: Future A Assumptions ...................................................................................................................................... 48Table 8: Future B Assumptions ...................................................................................................................................... 49Table 9: Future C Assumptions ...................................................................................................................................... 50Table 10: Summary of Modeling Results ................................................................................................................ 67Table 11: Gas to Renewables Comparison ........................................................................................................... 68Table 13: EAI Projects Approved in Appendix A of MTEP17 .................................................................. 77Table 14: EAI Projects Submitted as Target Appendix A in MTEP18............................................... 78Table 15: EAI Projects to be Submitted as Target Appendix A in MTEP19 ............................... 79

LIST OF FIGURES

Figure 1: Fuel Mix ...................................................................................................................................................................... 15Figure 2: Capacity Mix ........................................................................................................................................................... 17Figure 3: EAI Capacity Position....................................................................................................................................... 18Figure 4: EAI Energy Requirements .............................................................................................................................. 19Figure 5: Changes and Opportunities Within the Utility Industry........................................................ 24Figure 6: EAI IRP Load Forecasts ................................................................................................................................. 29Figure 7: DSM Categories .................................................................................................................................................... 31Figure 8: Load Forecast DSM Impacts ...................................................................................................................... 34Figure 9: Technology Screening Curve Illustration .......................................................................................... 35Figure 10: Historical Utility-Scale Solar Capital Costs ................................................................................. 37Figure 11: Levelized Real Cost of Electricity for Renewables ................................................................ 39Figure 12: Lithium Ion Battery Costs ......................................................................................................................... 40Figure 13: Natural Gas Price Forecast and Sensitivities ............................................................................ 46Figure 14: CO2 Price Forecast ......................................................................................................................................... 47Figure 15: Average Annual MISO South Non-EAI LMP ................................................................................. 51Figure 16: DR Resource Alternatives .......................................................................................................................... 54Figure 17: EE Resource Alternatives ........................................................................................................................... 54Figure 18: Future A Supply Additions........................................................................................................................ 55Figure 19: Future A Capacity Mix ................................................................................................................................. 56Figure 20: Future A Energy Mix ...................................................................................................................................... 56Figure 21: Future B Supply Additions ........................................................................................................................ 57

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Figure 22: Future B Capacity Mix ................................................................................................................................. 57Figure 23: Future B Energy Mix ...................................................................................................................................... 58Figure 24: Future C Supply Additions ....................................................................................................................... 59Figure 25: Future C Capacity Mix ................................................................................................................................. 59Figure 26: Future C Energy Mix...................................................................................................................................... 60Figure 27: Future A Sensitivity Supply Additions .............................................................................................. 61Figure 28: Future A Sensitivity Capacity Mix ....................................................................................................... 61Figure 29: Future A Sensitivity Energy Mix ............................................................................................................ 62Figure 30: Future B Sensitivity Supply Additions .............................................................................................. 63Figure 31: Future B Sensitivity Capacity Mix ....................................................................................................... 64Figure 32: Future B Sensitivity Energy Mix ............................................................................................................ 64Figure 33: Future C Sensitivity Supply Additions.............................................................................................. 65Figure 34: Future C Sensitivity Capacity Mix ....................................................................................................... 66Figure 35: Future C Sensitivity Energy Mix ............................................................................................................ 66

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A B B R E V I A T I O N S & D E F I N I T I O N S

ABBREVIATIONS & DEFINITIONSACE Affordable Clean EnergyADEQ Arkansas Department of Environmental QualityAECC Arkansas Electric Cooperative CorporationAILC Agricultural Irrigation Load ControlAMI Advanced Metering InfrastructureANO Arkansas Nuclear OneAPSC Arkansas Public Service CommissionCCGT Combined Cycle Gas TurbineCCR Coal Combustion ResidualsCEO Chief Executive OfficerCPP Clean Power PlanCSAPR Cross-State Air Pollution RuleCT Simple Cycle Combustion TurbineDLC Direct Load ControlDR Demand ResponseDSM Demand-Side ManagementEAI Entergy Arkansas, Inc.EE Energy EfficiencyEGU Electric Generating UnitEIA Energy Information AdministrationELG Effluent Limitation Guideline RuleEPA Environmental Protection AgencyFIP Federal Implementation PlanGW, GWh Gigawatt, Gigawatt HourHVAC Heating, Ventilation and Air ConditioningICF ICF International, Inc.IRP Integrated Resource PlanISES Independence Steam Electric StationkW, kWh Kilowatt, Kilowatt HourLMR Load Modifying ResourceMISO Midcontinent Independent System OperatorMLG Modified Load GrowthMTEP MISO Transmission Expansion PlanMW, MWh Megawatt, Megawatt HourNAAQS National Ambient Air Quality StandardNERC North American Electric Reliability CorporationNOx Oxides of NitrogenOISR Optional Interruptible Service RiderPOV Point of ViewPPA Power Purchase AgreementPV Solar PhotovoltaicRICE Reciprocating Internal Combustion EngineRPOC Resource Planning and Operations CommitteeRTO Regional Transmission OrganizationSAE Statistically Adjusted End-UseSIP State Implementation PlanSERC Southeastern Electric Reliability CouncilSO2 Sulfur DioxideSSRP Strategic Supply Resource PlanTOU Time-of-UseWB White Bluff Steam Electric StationUPC Usage Per CustomerUPP Union Power PlantWIIN Act Water Infrastructure Improvements for the Nation Act

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EXECUTIVE SUMMARY

For more than a century, Entergy Arkansas, Inc.’s (“EAI” or the “Company”) hasprovided safe, reliable, and affordable electricity to its customers in Arkansas. EAIcontinues to serve its diverse, growing customer base by proactively planning for futureresource needs by the most reliable and economic means possible.

This document describes EAI’s long-term Integrated Resource Plan (“IRP”) for the studyperiod 2020-2039 and is intended to provide Arkansas Public Service Commission(“APSC” or the “Commission”) and stakeholders insight into the Company’s long-termplanning process for meeting future demand and energy needs. Similar fundamentaluncertainties remain when compared to EAI’s most recent IRP, which was filed with theCommission on October 31, 2015. These uncertainties include advances in renewabletechnologies and their associated costs, future natural gas prices, economics ofexisting generation, and prospective changes in environmental regulations. Based onsubsequent analysis, EAI’s total generating capacity is forecasted to be short of itspeak customer demand plus reserve margin target in 2025, coinciding with theassumed deactivation of the Company’s Lake Catherine resource, or potentially soonergiven uncertainty around near-term resource assumptions. This deficit expands overtime as forecasted customer demand increases and existing resources reach the endof their assumed useful lives.

As with the Company’s most recent IRP, the 2018 IRP utilized a futures-based approachby which three future worlds were constructed in order to reasonably bookend a broadrange of future uncertainties. These futures were supplemented with sensitivity cases,which provide insight as to how each future’s portfolio of resources reacts to possiblechanges in key input assumptions. An economically optimal portfolio of both supply-side and demand-side resources was developed for each of the three futures andsensitivity cases. A summary of the modeled portfolios is shown in the table below.

Based on the results of the IRPanalysis, it is reasonable toconclude that EAI’s future supply-side resource additions will likelyconsist of a mix of both naturalgas-fired and renewable energyresources. The total amount,timing, and technology mix of new supply-side capacity additions are each uncertain.Based on this uncertainty, EAI has not established any specific targets for traditional orrenewable generation additions as part of this IRP analysis.

2018 IRP Results Future A Future B Future CTotal IncrementalInstalled Capacity: 6,660 MW 4,984 MW 7,128 MW

Natural GasCapacity Additions: 68.4% 94.0% 67.5%

Renewable CapacityAdditions: 31.6% 6.0% 32.5%

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The IRP’s future resource portfolios are developed consistent with the Commission’sResource Planning Guidelines but do not represent planning decisions by EAI. Rather,the Company’s specific long-term resource planning actions (e.g., capacity additions)are typically subject to review and approval by the Commission. In the same respect,the IRP’s assumptions regarding the cost and availability of various supply-sideresources do not reflect the actual cost for implementing those options. They aremerely planning assumptions, with the actual costs to be determined at a later time,likely through a market solicitation. In addition, while the IRP seeks to address EAI’scapacity needs, this approach should not be read to foreclose a future resource thatmay provide significant energy value to EAI’s customers, and it is not EAI’s intent to doso.

While no specific approvals are sought for this IRP pursuant to the Commission’sResource Planning Guidelines, the Action Plan outlined in Section IV of the IRP reflectsEAI’s present expectations regarding the planning actions that can be expected overthe next several years based on the relevant information available at that time.

The 2018 IRP Action Plan consists of seven action items, which are summarized below:

1. Complete Build-Own-Transfer ofSolar PV Capacity

As a result of EAI’s 2017 Request for Proposals for Build-Own-Transfer SolarResources, EAI has made selections and is currently working toward acquiringadditional solar PV generation by 2021.

2. Supply-sideResource Additions

EAI will monitor its load and capability position and take steps to add supply sideresources for both traditional and/or renewable resources as warranted. Acompetitive solicitation may be issued in 2019 for long-term resources.

3. Potential 2025Capacity Need

EAI will complete an evaluation of the availability of Lake Catherine Unit 4 past theassumed deactivation date of 2025. In combination with Action Item 2 above, EAIwill update the load and capability position in order to monitor the capacity needin 2025.

4. Demand-sideResourceOpportunities

EAI will seek and evaluate cost-effectiveness and feasibility for potentialprojects/programs to gain energy efficiencies in addition to its existing ArkansasEnergy Efficiency Program Portfolio.

5. Continueparticipation in EE

EAI will continue to offer cost-effective EE and DR programs within the Commission’sRules for Conservation and EE Programs and subsequent future Commission ordersas provided through Arkansas State law.

6. CoalEnvironmentalCompliance

EAI will continue to monitor changes in environmental law and regulations at thestate and federal level and evaluate options for environmental compliance for theEAI coal units.

7. StakeholderEngagement Process

Stakeholder engagement has been an important part of the development of this IRP.An immediate priority will be for EAI to closely review the stakeholder report andtake steps to address concerns and suggestions.

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I. INTEGRATED RESOURCE PLAN BACKGROUND AND CONTEXT

1. INTRODUCTION

This document describes EAI’s long-term IRP for the period 2020 – 2039. This is thefifth IRP filed by EAI since the APSC adopted its Resource Planning Guidelines in OrderNo. 6 in Docket No. 06-028-R. Similar to prior IRPs, the 2018 IRP reflects the fact thatuncertainty remains an issue that must be considered in long-term resource planning,with no outcome providing absolute certainty as to the appropriate path for the utilityto take. In other words, the uncertainties that dominated EAI’s 2015 IRP filed with theCommission on October 31, 2015 (e.g., uncertainties associated with potentialenvironmental regulation and advances in renewable resource technology) still remainbut have been expanded to include other uncertainties, such as the impact and role ofmore significant amounts of renewable generation in the market and changes incustomer preferences, something that EAI intends to continue to research and monitor.

EAI’s process for preparing this IRP considered potential future scenarios in whichvarious resource plans could be evaluated. As with EAI’s 2015 IRP, this IRP was (i)developed by EAI’s Resource Planning and Operations Staff, (ii) reviewed by EAI’sResource Planning and Operations Committee (“RPOC”), and (iii) approved by EAI’scurrent President and Chief Executive Officer (“CEO”), Laura R. Landreaux.

As indicated above, this IRP does not provide a fixed path for future EAI resourceplanning. Rather, EAI’s specific long-term resource planning actions (e.g., capacityadditions) typically are subject to review and approval by the Commission. While nospecific approvals are sought for this IRP pursuant to the Commission’s ResourcePlanning Guidelines, the Action Plan contained within this IRP reflects EAI’s currentexpectations regarding the planning actions it will take over the next several years.

2. RESOURCE PLANNING OBJECTIVES

EAI has established a set of resource planning objectives to guide its development ofthe IRP. These planning objectives were recommended by the RPOC and approved byEAI’s former President and CEO Hugh McDonald on May 16, 2012. During the nextplanning cycle, EAI intends to review and update, if necessary, its planning objectives,which will remain focused on four key areas: cost, risk, reliability, and sustainability.EAI’s resource planning objectives are shown in Appendix A.

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3. REGULATORY CONTEXT FOR EAI’S IRP

In 2006, the Commission adopted an IRP rule requiring APSC-jurisdictional utilities tofile an IRP at least every three years.1 The rule required that utilities would immediatelyfile their then-current resource plans. EAI met that obligation by filing the StrategicSupply Resource Plan (“SSRP”) that was in place at that time. EAI’s next resource planwas filed in 2009, and included the results and report of a stakeholder input processconducted for EAI’s 2009 IRP, as well as more comprehensive considerations ofdemand-side management and load control options. For EAI’s 2012 IRP, EAI modifiedits stakeholder process, reviewing actual study results with stakeholders rather thanonly reviewing high-level study assumptions and plans, as EAI did for its 2009 IRP. Inaddition, EAI addressed numerous questions from stakeholders, presented at openmeetings or in writing to EAI, with written responses provided for all such questions.

For the 2015 IRP, EAI’s stakeholder process proved to be far more interactive thanprior stakeholder processes conducted by the Company, with numerous meetings andconference calls directed by the stakeholders with EAI participation and input. EAI takesthis opportunity to note the extensive work by the Stakeholder Group on this IRP,which is reflected in the Stakeholder Comments that were attached to the 2015 IRP.These comments reflected the diversity of the views held by various stakeholders,which to their credit appear to have been resolved in an amicable manner.

For this IRP, EAI’s Stakeholder Engagement Process began in May 2018 with distributionof a detailed slide presentation describing proposed assumptions, inputs and modelingframework. The materials, while still preliminary, were posted to EAI’s IRP website2 .Additional meeting materials, which included preliminary modeling results from all threeFutures, were provided to stakeholders in advance of the in-person stakeholder meetinghosted by EAI in June 2018. The meeting was well-attended with representation frommany stakeholder groups. The agenda included an update on the status of EAI’splanning activities since 2015, assumptions and modeling framework for the 2018 IRP,as well as preliminary modeling results and a discussion of challenges andobservations. In response, during June and July 2018 over 100 detailed questions weresubmitted to EAI by stakeholders, to which EAI responded via follow-up postings to theIRP website. Most of the questions received were responded to within a week ofreceipt. In August 2018, EAI hosted a conference call with the Stakeholder Committeeto have a technical discussion of the Committee’s feedback regarding EAI’s IRP

1 See Order No. 6 in APSC Docket 06-028-R2 http://www.entergy-arkansas.com/integrated_resource_planning

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modeling. Finalized portfolio optimization modeling results for all Futures andSensitivities were posted to EAI’s IRP website on October 4th, 2018.

4. THE 2015 IRP ACTION PLAN

The 2015 EAI IRP Action Plan contained six action items, some of which are still inprocess. The current status of each action item is described below:

1. Coal Unit Environmental Compliance – EAI has resolved its regional hazecompliance requirements for its White Bluff Steam Electric Station (“WB”) bycommitting to burn low sulfur coal and to cease burning coal at WB by 2028.EAI continues to work with the Arkansas Department of Environmental Quality(“ADEQ”) and other interested parties regarding long-term environmentalcompliance issues at the Independence Steam Electric Station (“ISES”). EAI willcontinue to monitor changes in environmental law and regulations at the stateand federal level and evaluate options for environmental compliance for the EAIcoal units.

2. Clean Power Plan – EAI is continuing to monitor changes in environmental law atthe state and federal level. Since the Clean Power Plan was published in theFederal Register in October 2015, there have been various legal challenges.Recently, the Environmental Protection Agency (“EPA”) has proposed to repealthe Clean Power Plan and published the proposed Affordable Clean Energy (ACE)Rule, which is intended to replace the Clean Power Plan. See infra Section III ofthis IRP for a detailed discussion of environmental regulation/compliance issues.

3. Complete Acquisition of Power Block 2 from Union Power Plant (“UPP”) – EAIcompleted its acquisition of Power Block 2 from the UPP in March 2016, addingover 500 MW to EAI’s generation fleet.

4. Continue Participation in Energy Efficiency – Since 2015, EAI has addedapproximately 125 MW of peak period savings as a result of expanded DSM andEE programs. A detailed discussion of EAI’s participation in DSM and EE isprovided infra in Section III.

5. Supply-side Resource Additions – In addition to the completed acquisition ofPower Block 2 from Union Power Plant in item 3 above, EAI also has added twolong-term Power Purchase Agreements (“PPAs”) to its portfolio since the 2015IRP. A detailed discussion of these solar PPAs is provided infra in Section II.

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6. Stakeholder Engagement Process – EAI implemented changes in the IRP projectschedule as well as the modeling based on feedback received through theStakeholder Engagement Process in the 2015 IRP, as well as EAI’s experiencesand observations. A detailed discussion of this process is provided in Section V.

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II. EAI RESOURCE PLANNING

The IRP plays an important role in the planning of EAI’s future resource portfolio byproviding a comprehensive look at long-term themes and tendencies in designing andleveraging a diverse, balanced, and forward-thinking portfolio of resources to EAIplanners, as well asstakeholders. While theselong-term and forward-lookingindicators are importantguides to resource planning,the IRP fulfills a distinctlydifferent purpose and processfrom near-term, specificresource decisions thattypically are presented to theCommission for approval.

The considerations detailed in the following pages are focused on efficiently meetingall of our customers’ ever-changing supply needs. EAI’s IRP strategy ensures we aretaking the necessary steps today to continue to enhance reliability and affordabilitywhile mitigating risks that could impact either of these factors for our customers asmuch as possible. This approach also provides the flexibility EAI requires to respondand adapt to a constantly shifting utility landscape.

The study period for the 2018 IRP is 2020 through 2039 and outlines the currentenergy landscape as well as the challenges and opportunities that lie ahead. A twenty-year study period was chosen for this IRP in order for EAI to evaluate long-term trendsunder a broad range of possible future outcomes. As in EAI’s previous IRPs, the 2018IRP is guided by EAI’s Resource Planning Objectives, which focus on four key areas:cost, risk, reliability and sustainability. The full details of the Resource PlanningObjectives are available in Appendix A.

1. EXISTING RESOURCES

EAI’s customer base has grown to over 709,000 residential, commercial, industrial, andgovernmental customers located in 63 of Arkansas’ 75 counties, covering over 40,880square miles. The Company currently controls, through ownership or through PPAs, adiverse array of generating resources totaling approximately 5,365 MW to serve thesenative load customers. The Company’s nuclear power resources include 1,722 MW fromthe two-unit Arkansas Nuclear One (“ANO”) plant located near Russellville and 308 MW

Long-termPlanning

•3-year update cycle•Up to 20 years into

the future•Example: IRP

Near-termDecision Support

•Ongoing•Project-specific, 1-

5 years•Examples: RFPs, self-

builds, ordeactivationevaluations

IRP Action Plan

Actual Results

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from the Grand Gulf Nuclear Station (“Grand Gulf”) near Port Gibson, Mississippi, undera long-term PPA. EAI also utilizes 1,024 MW from coal-fired generation at WB and ISESlocated near Redfield and Newark. EAI shares ownership of WB with the ArkansasElectric Cooperative Corporation (“AECC”) and several municipal electric utilities andshares ownership of ISES with Entergy Mississippi, Inc., AECC, Entergy Power Inc., anEntergy affiliate, and several municipal electric utilities. The Company’s generation fleetis rounded out with 92 MW of hydro-electric capacity along the Ouachita River Valleyand 2,139 MW of natural gas-fired generation that includes 606 MW from the HotSpring Plant, 505 MW from the Ouachita Plant and 501 MW from Power Block 2 ofUPP, which are modern combined cycle gas turbines (“CCGT”). Figure 1 below showsthe percentage, by fuel type, of energy sources serving EAI’s native load in 2017.

FIGURE 1: FUEL MIX

In addition to these generating resources, EAI’s portfolioalso includes resources that provide capacity valuethrough reducing customer load. These load modifying

resources (“LMRs”) contributed nearly 230 MW combined of capacity including valueassociated with reduced line losses and reserves. EAI also manages a portfolio ofenergy efficiency (“EE”) programs that produce both energy savings for customers anda reduction in load served for the company. These programs have reduced thecompany’s load behind the customer meter by an incremental 125 MW since 2015 andan aggregate 348MW since programs were introduced in 2008.

62%21%

10%

7% 1%

Sources of Energy Serving EAI's Native Load in 2017

Nuclear

Natural Gas

Coal (EAI Share Only)

Purchased Power

Hydro

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A new addition to EAI’s portfolio sincethe 2015 IRP and a result of EAI’s 2014Request for Proposals3, EAI has executeda long-term PPA for an 81 MW solarphotovoltaic resource located nearStuttgart, Arkansas named StuttgartSolar.4 The Commission issued Order No.5 in Docket No. 15-014-U on September24, 2015, approving the PPA. Theresource achieved commercial operationsahead of schedule in December 2017. EAI’s PPA began with the start of the 2018/19MISO Planning Year, which was June 1, 2018.

Additional information about EAI’s existing resources is available in Appendix B.

2. PLANNED RESOURCES

Since 2015 EAI has sought regulatory approval for additional renewable generation. Asa result of EAI’s 2016 Request for Proposals for Renewable Generation Resources, EAIhas executed a long-term PPA for a planned 100 MW solar photovoltaic resource tobe located near Lake Village, Arkansas, to be called Chicot Solar5. The Commissionissued Order No. 4 in Docket No. 17-041-U on June 18, 2018, approving the PPA.The 2018 IRP assumes the resource achieves commercial operations and the PPAbegins by 2020.

Additionally, in its 2017 Request for Proposals for Build-Own-Transfer Solar PhotovoltaicResources EAI sought up to 200 MW of solar generation to add to its resourceportfolio. EAI has not yet brought this future resource before the Commission to seekapproval; however, EAI expects to initiate those proceedings in the near future. Theseacquisitions would provide low-cost, emissions-free capacity and energy to EAI’sportfolio. The 2018 IRP assumes Commission approval is received and commercialoperation is achieved by 2021.

Under the assumption that the planned resources described above proceed as planned,the 2018 IRP reflects a total of approximately 5,859 MW of resources in EAI’s portfolio

3 Information on EAI Requests for Proposals can be found at:http://www.entergy-arkansas.com/rfp/energy_capacity.aspx.4 Docket No. 15-014-U5 Docket No. 17-041-U.

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by 2021 on an effective capacity basis 6 . The diversity of EAI’s currently plannedresource portfolio in 2021 is shown in Figure 2 below.

FIGURE 2: CAPACITY MIX

3. FUTURE OF EXISTING RESOURCES

As indicated above, uncertainty is an ongoing issue that resource planners mustconsider in preparing long-term resource plans. In subsequent sections, EAI will reviewa number of factors that are assessed to guide and inform the portfolio designstrategies and other issues facing EAI’s planners.

Developing an IRP requires making assumptions about the future operating lives ofexisting generating units. Two key issues in this determination are the effective date offuture environmental compliance requirements and whether the investments needed forEAI’s older units to keep operating in compliance with those regulations are economicalcompared to alternative capacity resources. The IRP includes deactivation assumptionsfor existing generation in order to plan for and evaluate the best options forreplacement capacity over the planning horizon. These deactivation assumptions do notconstitute a definitive deactivation schedule, but are used as planning tools and helpto prompt cross-functional reviews and recommendations. It is not unusual for these

6 Effective capacity is 50% of installed capacity for solar resources, 15.6% for wind resources and 100% forconventional resources. LMRs receive peak hour capability plus reserve margin and transmission losses.

35%

34%

17%

7%

6% 1%

2021 Resource Portfolio by Fuel Type

Natural Gas

Nuclear

Coal

Interruptible Load

Solar

Hydro

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assumptions to change over time given the dynamic use and operating characteristicsof generating resources.

It is important to recognize that assumptions related to these uncertainties aboutoperating lives of existing generating units do not reflect actual decisions regarding thefuture investment in resources or the actual dates that generating units will beremoved from service. Key uncertainties related to environmental compliance, forexample, include the requirements of rules still under development, the effective datesfor compliance, the outcome of current litigation, congressional activity, and thepossibility of extensions of the compliance deadlines. Rather, unit-specific portfoliodecisions, e.g. sustainability investments, environmental compliance investment, or unitdeactivations, will be made at the appropriate time and will be based on economicand technical evaluations considering such factors as projected forward costs,anticipated operating roles, and the cost of supply alternatives. These factors aredynamic, and as a result, actual decisions may differ from planning assumptions asgreater certainty is gained regarding requirements of legislation, regulation and relativeeconomics. Accordingly, EAI’s resource plans seek to retain the flexibility to respond tochanges in circumstances up to the time that a commitment is required to be made.

4. RESOURCE NEEDS

A number of factors are considered and evaluated in order to understand anddetermine EAI’s resource needs:

· Long-Term Capacity Requirements - EAI is projected to need new generatingcapacity over the course of the 20-year IRP planning period in order to reliablyserve customers. Taking deactivation assumptions into account, short of any newadditions to generation beyond the planned resources described earlier, the long-term deficit is expected to exceed 1,000 MW by 2028. This need grows to over4,700 MW by the end of the planning horizon. Figure 3 below shows EAI’s portfolioof existing resources, including both generating units and demand-side capacity,and planned resources, as described above, compared to EAI’s peak load-plus-reserve-margin target. An assumption for future energy savings due to continuedand expanded EE programs is included in the peak load. The total capability isshort of the peak load plus reserves by as soon as 2025. The deficit expands overtime as expected loads increase and older generating units reach an assumed endof useful life.

FIGURE 3: EAI CAPACITY POSITION

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· Energy Requirements - In addition to capacity requirements, EAI evaluates how itsexisting and planned resources effectively meet its energy requirements to helpinform future portfolio design. As resources deactivate and capacity requirementsincrease, EAI will look to balance energy producing and peaking generation toeffectively and efficiently meet customer requirements.

FIGURE 4: EAI ENERGY REQUIREMENTS

· Customer Usage – Of course, both capacity and energy resource needs are drivenby customers’ consumption and preferences. Customer conservation efforts, some ofwhich are currently driven by energy efficiency programs, have already directly

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1,000

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Existing Capacity LMR & DRR Planned Capacity Load + Reserve Target

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GWh

Baseload Intermediate Peaking Energy Requirement

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affected resource needs as discussed further in Section III. The type, size andtiming of future resource needs may be affected as customers gain additionalresources to manage consumption, such as those that will be enhanced byAdvanced Metering Infrastructure (“AMI”) as well as increased accessibility to rooftopsolar or battery storage technology

EAI’s long-term planning process and the evaluation outlined in this IRP helps informhow EAI will meet its future capacity and energy requirements needed to continue toreliably serve its customers. EAI’s planning approach is to use a diverse portfolio ofenergy generation resource alternatives, located in relatively close proximity tocustomer load with flexible attributes to help provide sufficient capacity during peakdemand periods as well as adequate reserves, ensuring EAI is able to continueproviding safe and reliable service at a just and reasonable cost for our customers,given the primary objective of risk mitigation.

5. TRANSMISSION PLANNING

The Company’s transmission planning group ensures that the transmission system: (1)remains compliant with applicable North American Electric Reliability Corporation(“NERC”) standards, and related Southeastern Electric Reliability Council (“SERC”) andEntergy’s local planning criteria, and (2) is designed to efficiently deliver energy to end-use customers at a reasonable cost. Since December 2013, EAI has been aTransmission Owning member of MISO, a Regional Transmission Organization (“RTO”).MISO was approved as the nation's first RTO in 2001 and is an independent nonprofitmember-based organization that supports the delivery of wholesale electricity andoperates energy and capacity markets in 15 U.S. states and the Canadian province ofManitoba. In cooperation with stakeholders, MISO manages 65,000 miles of high voltagetransmission and 200,000 megawatts of power generating resources across itsfootprint. Since joining MISO, EAI has planned its transmission system in accordancewith the MISO Tariff.

A key responsibility of MISO is the development of the annual MISO TransmissionExpansion Plan (“MTEP”). EAI is an active participant in the MISO MTEP developmentprocess, which is currently in development of the MTEP 19 cycle. Participation in theMISO MTEP process is the method by which EAI’s transmission plan is incorporated intothe annual MTEP document. The overall planning process can be described as acombination of “Bottom–Up” projects identified in the individual MISO TransmissionOwner’s transmission plans which address issues more local in nature and are drivenby the need to safely and reliably provide service to customers, and projects identified

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during MISO’s “Top-Down” studies, which address issues more regional in nature andprovide economic benefits or address public policy mandates or goals.

Through these MTEP related activities, EAI works with MISO, other MISO TransmissionOwners, and stakeholders to promote a robust and beneficial transmission systemthroughout the MISO region. EAI’s participation helps ensure that opportunities forsystem expansion that would provide benefits to EAI customers are thoroughlyexamined. This combination of Bottom-Up and Top-Down planning helps ensure allissues are addressed in an effective and efficient manner.

EAI’s transmission strategy is centered upon meeting the evolving needs of itscustomers for safe and reliable energy. Each year the EAI transmission system isthoroughly studied to verify that it will continue to provide EAI customers with reliableand safe service through compliance with all applicable NERC standards as well asEntergy’s local planning criteria and guidelines.

These studies identify potential system conditions where reduced reliability may occurin the future. Additional studies are then performed to develop projects and determinewhat, where and when system upgrades are required to address the future reliabilityconcerns. This annual review identifies any transmission system reinforcementsnecessary to provide reliable and safe service in response to changing systemconditions. These studies consider the effects of overall system load growth,retirements of existing generation resources, implementation of new generatingresources, the adequacy of new and existing substations to meet local load, theexpected power flows on the bulk electric system, and the resulting impacts on thereliability of the EAI transmission system.

These reliability studies result in projects which are presented annually to the EAIRPOC and ultimately must be approved by the EAI President and CEO. Once approved,these reliability projects are submitted to MISO for regional study, to 1) verify that thereliability need exists, 2) to verify that the proposed solutions solve the reliability need,and 3) to provide stakeholders the opportunity to discuss alternatives. Additionally,MISO performs other studies each year to consider planning issues including marketefficiency projects and customer driven projects, such as those driven by generatorinterconnection requests and opportunities for interregional projects with neighboringplanning regions.

The result of the MISO MTEP process is a compilation of transmission projects that areneeded to address system reliability requirements, improve market efficiency, and/orprovide specific system benefits as delineated in the MISO Tariff. The MTEP identifies

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solutions to meet regional transmission needs and to create value opportunitiesthrough the implementation of a comprehensive planning approach.

Each MTEP document is identified by the year in which it was completed. Appendix Aof each MTEP cycle lists and briefly describes the transmission projects that have beenevaluated, determined to be needed and subsequently approved by the MISO Board ofDirectors. Since joining MISO, EAI has submitted projects into MTEP 14, MTEP 15, MTEP16, MTEP 17, MTEP 18, and is currently in preparation for MTEP 19. The EAI projectsthat were approved for inclusion in Appendix A of MISO’s MTEP 17 cycle are providedin Appendix C, Table 13. Also, submitted Target Appendix A projects for MTEP 18 arelocated in Appendix C, Table 14, and proposed projects for Target Appendix A of MTEP19 are located in Appendix C, Table 15. These future transmission projects and othertransmission plans developed during the next three years will be important inputs toconsideration of future resource needs.

Integration of Transmission and Resource Planning

The availability and location of current and future generation on the transmissionsystem can have a significant impact on the long-term transmission plan, requirementsfor meeting NERC reliability standards, and efficiently delivering energy to customers ata reasonable cost. Like transmission, new generation must be planned well in advance,and due to the interrelationship of generation and transmission planning, looking farenough into the future and addressing potential generation needs is critical in meetingEAI’s planning objectives of low cost, improved reliability, and reduced risk.

The continued evaluation and condition of EAI’s generation fleet must be taken intoaccount for integrated generation and transmission planning. EAI’s planning assumptionincludes deactivation of existing generation resources during the planning horizon,which will have an impact on transmission reliability requirements without properreplacement generation.

6. DISTRIBUTION PLANNING

EAI has put in place programs that have and will continue to maintain and improve thereliability of our distribution lines and our distribution line infrastructure, while aimingto minimize customer outages. Customers directly benefit from improvements in linemaintenance, infrastructure, vegetation management, and substation reliability throughreduced outages and outage duration. Customers also benefit from the reduction incosts from extending the life of distribution assets and minimizing maintenance costswith respect to those assets.

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Modernization of the distribution system has several key components. One of them isthe replacement of existing physical infrastructure and distribution assets to providemore reliable service to our customers. This aspect of modernization is addressed onan ongoing basis through the annual Transmission and Distribution Plan. Additionally,via the modernization of distribution system technology, EAI can gather faster andmore accurate data from the distribution system than was previously possible. With thisinformation, the Company can make quicker, more informed decisions about impacts tothe system and thereby potentially reduce both the number and duration of outages,improving overall system reliability. For example, improvements to the speed andaccuracy of crew deployments during customer outages would improve outagerestoration times and ultimately lower costs to customers.

EAI’s approach to grid modernization will continue to be a thoughtful and balancedanalysis of the costs and benefits for customers, with a preference for technologiesthat have a track-record of delivering on their promises of benefits. The Company mustbe able to respond to and implement these emerging technologies in a timely manner.

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III. THE 2018 INTEGRATED RESOURCE PLAN

1. KEY INPUTS AND ASSUMPTIONS OVERVIEW

1.1 CHANGING UTILITY

Guided by the Resource Planning Objectives, EAI’s resource planning process seeks tomaintain a portfolio of resources that reliably meets customer power needs at a justand reasonable supply cost while minimizing risk exposure. While the landscape withinthe electric utility industry is changing, the Resource Planning Objectives are asimportant and relevant as ever, and this IRP offers early insight for opportunities torespond to this evolving environment.

FIGURE 5: CHANGES AND OPPORTUNITIES WITHIN THE UTILITY INDUSTRY

EAI recognizes the way customers consume energy is changing, so the way thecompany plans for, produces, and delivers the power customers rely on must continueto evolve as well. EAI strives to have a planning process that provides for the flexibilityneeded to better respond to this constantly-evolving environment. Below areconsiderations, changes, and opportunities that have comprised part of EAI’s 2018 IRPdevelopment.

Customer Preferences

With advancements in technology and evolving priorities, both within and outside of thetraditional utility framework, customer expectations will continue to change. Theevolution and adoption of customer-centric technology and services has created a shiftin customer preferences and expectations—both in terms of how the power they use isgenerated and the services and offerings they value from utility companies.

Today’s energy customers are using energy more efficiently than ever before, due toboth an increasing emphasis on social responsibility and sustainability and advances inenergy efficiency standards. As specified in the Resource Planning Guidelines, EAIapproaches energy efficiency with the broader goal of enhancing the generation,delivery and use of energy, recognizing that a well-designed electric system, with theproper mix of generating resources, is just as important to reducing customer costs

CustomerPreferences

AdvancingTechnology

UtilityActions

IncreasedCustomerValue

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and bills as are programs aimed at educating customers how to efficiently managetheir usage.

Customers are also seeking more options in the generation and delivery of energy,including how they interact with, understand, and manage their own energy use, as wellas the actual sources from which their energy is derived. Increasingly, our customersare becoming more interested in sourcing their power from cleaner, more sustainablesources of energy, including natural gas, nuclear, and renewables like solar. Asreflected in EAI’s AMI proceeding in Docket No. 16-060-U, EAI’s deployment of AMI is inresponse to ever-evolving customer expectations regarding the provision of electricservice and technological innovation that is changing the way energy is supplied anddistributed. EAI’s interest is in actively engaging its customers to obtain a better senseof those expectations and the ways in which EAI can bring offerings to the marketplaceto meet those expectations.

EAI is focused on achieving a better understanding of these changing customerpreferences and the IRP is one set of input information EAI can leverage to helpaccomplish that goal. That will allow EAI to:

· Develop a comprehensive outlook on the future utility environment so we canmore effectively anticipate and plan for the future energy needs of ourcustomers and region.

· Incorporate new, smart technologies and advanced analytics to better assesswhere expanding resource alternatives can be leveraged, and plan forimprovements and enhancements to the electrical grid.

· Continue integrating and offering the innovative products and services ourcustomers want and expect as is reasonable.

Advancing Technology

Technological advancements provide the energy industry increased opportunities andalternative pathways to plan for and efficiently meet customers’ energy needs. Fromimproving the reliability and efficiency of energy production and delivery of that energyto customers, to more customer facing opportunities, like storage, conservation, andAMI-enabled options, these innovations can strengthen reliability and increaseaffordability for the homes, businesses, industries, and communities that EAI serves.These new technologies also support the continued development and expansion ofsustainability efforts while addressing EAI’s long-term planning objectives, outlined infurther detail below.

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The deployment of advanced meters and development of smart energy grids, forexample, are enabling the entire utility industry to better understand the new andchanging ways in which customers are using energy. This allows energy companies tomake more informed decisions and provide tailored customer solutions throughenhancements to electric infrastructure and the adoption of new products and services.

Utility Actions

EAI understands that how our customers use energy is changing and these changingneeds and expectations will inform the IRP process as well as EAI’s approach tocustomer service. As a utility provider, it is incumbent upon EAI to adapt to theevolving needs of customers. The scope and nature of our business will and mustchange in response to the changing landscape. EAI’s objective is to find, deploy, andintegrate the right mix of technology, products, and services that provide solutions toserve the needs of customers while maintaining the reliability they need and expect.

To do that, EAI is evaluating and incorporating new, customer-centric technology, anddesigning an energy portfolio that leverages a more diverse mix of energy resources—including a greater reliance on what have recently become cost-effective renewable andclean energy sources—to adapt to the changing needs of customers. EAI, as comparedto individual customers, is better positioned to efficiently integrate these newtechnologies and solutions into the electric grid. All the while, EAI is keepingaffordability and reliability for its customers at the forefront of its planning.

Increased Customer Value

By combining an understanding of what customers want with sound and comprehensiveplanning, we can deliver the types of services and products our customers expect whilecontinuing to address the traditional planning objectives of cost, reliability, and risk.Increasing the array of alternatives provides an opportunity to better meet our planningprinciples by providing a diverse portfolio of resources to meet long-term servicerequirements. A diverse portfolio mitigates customer exposure to price volatilityassociated with uncertainties in fuel and power purchase costs and risks that mayoccur through a concentration of portfolio attributes such as technology, location,large capital commitments, or supply channels. Additionally, by taking advantage ofincreased and evolving opportunities, EAI continues its effort of modernizing its supplyportfolio.

2. SALES AND LOAD FORECASTS

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As discussed in prior sections, future customer peak load and energy requirements arekey determinants of resource needs. A wide range of factors affect electric load in thelong-term, including:

§ Levels of economic activity and growth, including the rate at which newcustomers come into or leave a service area;

§ The potential for technological change to affect the efficiency of energyconsumption;

§ Potential changes in the purposes for which customers use electricity (e.g., theadoption of electric vehicles);

§ The potential adoption of end-use (behind-the-meter) self-generation technologies(e.g., rooftop solar panels); and

§ The level of energy efficiency measures adopted by customers.

Such factors may affect both the level and shape of load in the future, and, as aresult, peak loads may be higher or lower than projected levels. Similarly, industrialcustomer load factors may vary from current projections based on the age of acustomer’s facility and equipment as well as the economics of the markets in whichindustrial customers operate. Uncertainties in load may affect both the amount andtype of resources required to efficiently meet customer needs in the future.

In order to consider the potential implications of load uncertainties on long-termresource needs, three load forecast scenarios reflecting a range of outcomes wereprepared for the 2018 IRP, which forecasts are described below:

· The Reference Case load forecast reflects baseline model and inputassumptions, including near-term sales growth from a new industrial customer.

· The Low Case load forecast assumes weaker customer count growth, lowerResidential and Commercial usage-per-customer (“UPC”) attributable to strongerthan forecasted gains in organic energy efficiency, and lower industrial salesvolumes tied to potentially worsening economic conditions.

· The High Case load forecast assumes stronger customer count growth, higherResidential UPC attributable to weaker than forecasted gains in organic energyefficiency, and higher industrial sales tied to a strengthening economy.

Forecast Methodology

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The same load forecasting process used to develop each of the three load forecastcases described above has also been used in EAI’s previous IRPs. That process usescomputer software from Itron to develop long-term, hour-by-hour load forecasts. TheMetrixND™7 and the MetrixLT™8 programs are used widely in the utility industry, to thepoint where they may be considered an industry standard for energy forecasting,weather normalization, and hourly load and peak load forecasting.

EAI’s Retail Energy Forecast (“Sales Forecast”) is a primary input for developing theload forecast. Regression models are used for forecasting residential, commercial, smallindustrial and governmental revenue class electricity (“MWh”) sales as well as customercounts on a monthly billed sales basis. EAI’s largest industrial customers (the LargeIndustrial Segment) are forecasted individually.

Economic driver data used in the regression models, both historical and forecastedwere obtained from IHS Markit, Inc. and includes customized data for the EAI serviceregion as well as national drivers for a wide variety of variables. Statistically adjustedend-use (“SAE”) data from the U.S. Energy Information Administration (“EIA”), whichreflect historical electric consumption from appliances, HVAC systems, lighting, andother devices are also used in the regression models. Temperature data is the sameas used in the weather normalization analyses and is used in all models except forthose instances (such as for industrial class models) where no significant dependenceof sales to weather can be established. Actual weather data is used for historical timeperiods and normal cooling and heating degree days are used for forecasted periods.

The sales forecast for the residential class is derived from separate usage percustomer and customer count models, the outputs of which are multiplied together ona monthly basis to produce forecasted total sales volumes. For the other classes, thetotal usage is directly calculated by the models. The key drivers for the UPC andusage models are generally trends in average consumption such as decreases due toHVAC efficiency or increases due to individuals having more devices to plug-in (phones,computers, etc.) while customer count models are typically based on drivers such aspopulation or numbers of households. Additionally, the residential UPC and commercialusage models incorporate end-use variables such as appliance efficiencies and homesize to account for the impact of changing end-use characteristics over time. EAI usesa mix of SAEs and econometric data in its regression models to capture the effects of

7 MetrixND™ by Itron is an advanced statistics program for analysis and forecasting of time series data.8 MetrixLT™ by Itron is a specialized tool for developing medium and long term hourly load shapes that are consistentwith monthly sales and peak forecasts.

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changes in end-use data as well as changes in population, household counts, andother economic drivers.

EAI has had company-sponsored EE programs since 2008 with incremental annualprogram-year savings that began at 20 GWh, rising to more than 260 GWh in 2017.Due to the increasing levels of these programs over that time, which covers thehistorical estimation period for the residential and commercial forecasts, EAI hasemployed a new method since the 2015 IRP to account for the effects of the historicalEE programs on sales levels. This updated methodology, referred to as the add-backmethod or reconstituted sales method, also provides a means to calculate the futureeffects of continued EE programs as well as the build-up effects from prior years.Historical program EE savings were carried forward based on program measure life,with depreciation applied for future years. These aggregated EE savings were thenadded back to historical sales in EAI’s regression models to produce a forecasttrajectory as if there had never been any company-sponsored EE programs. From thispoint, assuming that future programs continue at current levels, the cumulative effectsof historical and future EE programs were decremented from the no-EE forecast toarrive at a final sales forecast. This methodology allows for more understanding of theeffects of each EE program as well as more precision on the net effect of future EEprogram levels.

To develop the load forecast, the monthly Sales Forecast is allocated to each hourbased on historical load shapes. Twenty-year “typical weather” is used to converthistorical load shapes into “typical load shapes.” For example, if the actual sales forEAI’s residential customers occurred during very hot weather conditions, the typicalload shape would flatten the historic load shape. If the actual weather was mild, thetypical load shape would raise the historic load shape. Each customer class respondsdifferently to weather, so each has its own weather response function. MetrixND™ isused to adjust the historical load shapes by typical weather, and MetrixLT™ is used tocreate the hourly load forecast.

The load forecast is grossed up to account for transmission and distribution linelosses. Unique distribution loss factors are applied to each revenue class after theforecast is developed. For example, EAI’s residential class is grossed up by a differentamount than the commercial class. The transmission line loss assumption is the valuecalculated by MISO for EAI’s Local Resource Zone for the 2018/19 Planning Year,which is 2.5%.

FIGURE 6: EAI IRP LOAD FORECASTS

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2.1 ARKANSAS ECONOMIC OUTLOOK

The economic outlook for EAI’s service territory, and the state of Arkansas in general,continues to show modest growth but lags behind the US in several key economicperformance indicators, including Total Employment, Population, Real Average Wage,and Real Personal Income growth.

As of August 2018, the compound annual growth rate for gross state product for2014-2021 was 1.4%9. Payroll employment10 across EAI’s service territory diverges fromsustained strong growth in the Jonesboro area, to modest growth in the Little Rockand Hot Springs areas, with a sharp decline in the Pine Bluff area. The overalleconomic environment in the EAI service territory is positive, which has historicallysuggested increased energy demand. However, increasing social and regulatory focuson energy efficiency, including the recent Commission mandate to increase EAI’s DSMprogram savings goal to 1.2%, will temper demand. The bright spot for demand in theEAI service territory comes from a new large industrial customer that has provided a

9 IHS Markit, Inc.10 Bureau of Labor Statistics, Current Employment Statistics, August 2018

4,500

4,600

4,700

4,800

4,900

5,000

5,100

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2039

Peak

Loa

d (M

W)

Low Reference High

Key Performance Indicators, 2018% Change, Y-O-Y Employment Population Real Average

WageReal Personal

Income

Arkansas 0.59% 0.50% 0.33% 0.33%

United States 1.66% 0.72% 0.82% 1.86%

©2018 IHS Markit, Inc.

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step change in EAI’s base load. In aggregate, higher energy demand from a healthyeconomy in the EAI service territory is offset by higher energy efficiency and solaradoption, resulting in a modest long term upward trend.

2.2 DEMAND-SIDE MANAGEMENT

EAI considers Demand-side Management (“DSM”) to be a valuable resource whenimplemented in a cost-effective manner compared to supply-side resources, and the2018 IRP reflects EAI’s continued commitment to DSM. In recent IRPs, EAI has includedDSM resource options in four categories: customer-sponsored DSM, existing Utility-sponsored DSM, Utility-sponsored DSM Growth, and potential DSM resources. While thefirst three categories are discussed here, the fourth category, potential DSM resources,was enhanced in development of the 2018 IRP, which is described in detail later in thissection. The potential DSM resources category represents additional investment inresources on the customer side of the meter that may be cost-effective in meetingEAI’s long-term resource needs. It is not a decrement to the Sales and Load Forecast,but rather is modeled dynamically alongside supply side resource alternatives, so it isincluded in the section below which discusses all modeled resource options. DSMplanning includes EE, demand response (“DR”), and interruptible loads. Each category isdescribed below.

FIGURE 7: DSM CATEGORIES

Customer-sponsored DSM

Customer-sponsoredDSM

•Improvements inenergy efficiency andconservation thatoccur without Utilityinvolvement.

•An assumption forthis type of DSM isincluded in the RetailSales Forecast.

Existing Utility-sponsored DSM

•Generally, largescale, regulatorapproved programsthat provideincentives to goabove and beyondefficiency standards.

•An assumption forthe impact ofexisting programs isincluded in the RetailSales Forecast.

Utility-sponsored DSMGrowth

•Represents theannual incrementalsavings produced byregulator-approvedprograms.

•An assumption forthe impact ofincremental programsis included in theRetail Sales Forecast.

Potential DSMResources

•These programs arelike existing Utilityprograms but requireregulatory approvalto implement.

•These resources aremodeled like asupply side resourceand are not includedin the retail salesforecast.

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EAI’s customers may elect to make EE improvements or take steps to reduce energyusage in their homes, businesses and communities without EAI’s involvement. Also, newrequirements for EE, such as new construction building codes and appliance or lightingefficiency standards, and new technologies, such as learning thermostats, may reducecustomer’s electricity usage or change energy usage patterns. This type of DSM isincluded in the development of the Sales Forecast described in the previous section.

Existing Utility-sponsored DSM

For several years, EAI has maintained and expanded its Arkansas Energy EfficiencyProgram Portfolio (“EE Portfolio”), which consists of generally large scale, regulator-approved programs that provide incentives to customers to go above and beyondcurrent EE standards. The comprehensive EE Portfolio is reviewed and approved by theCommission and developed in an attempt to meet the Commission’s utility EE targets,which are currently set at 0.9% of retail sales (excluding industrial opt-out). As part ofits current three-year EE plan, EAI’s approved EE targets increase to 1.0% for programyear 2019. In July 2018, the Commission set new EE targets of 1.2% of retail sales forprogram years 2020 through 202211.

Impacts of the existing EE Portfolio are included in the Sales Forecast referencedearlier in this section. The MW and MWh savings achieved by existing EE programs forthe 2017 Program Year can be found in EAI’s Arkansas Energy Efficiency ProgramPortfolio Annual Report, filed May 1, 2018 in Docket No. 07-085-TF.

In addition to its EE Portfolio, which currently includes two DR programs, AgriculturalIrrigation Load Control (“AILC”) and Direct Load Control (“DLC”), EAI also offers theOptional Interruptible Service Rider (“OISR”). Each of these programs allows EAI toeither reduce participants’ usage or send a request to participants to reduce usageduring an emergency situation. Although these resources reduce or shift load on thedemand side of the meter, EAI treats these resources the same way as its existingsupply-side capacity resources in the 2018 IRP analysis, as opposed to including as anoffset a decrement to the Sales Forecast. In 2018, the interruptible loads provide 250MW of total capacity savings. The assumption grows to 319 MW by the first year ofthe IRP study period (2020) based upon the expansion of a customer takinginterruptible service pursuant to a Commission-approved contract.

Utility-sponsored DSM Growth

11 Order 43 in Docket No. 13-002-U, effective July 13, 2018

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Beyond the existing DSM programs, the 2018 IRP assumes that EAI continues to growits EE Portfolio at an incremental level of 0.9% of retail sales per year, which isapproximately 260 GWh of additional savings per year at the meter. Note that theSales and Load Forecasts used in the 2018 IRP were developed prior to theCommission’s approval of new EE targets for the 2020 through 2022 program years. Aspreviously referenced, these new EE targets increased to 1.2% of retail sales.

This assumption is based on several factors. The 2018 IRP incremental Utility-sponsored EE assumption:

1. is based on the historical achievement of EE in a fuel cost environmentthat is at or lower than the 2018 IRP and with a greater number of SelfDirect customers than assumed in the 2015 IRP;

2. is consistent with a perceived desire of state policy makers to moderatethe cost of EE on the customer’s utility bills; and

3. is based on the belief that the EE market that has been built up over thelast 10 years will be sustainable in the foreseeable future.

Of course, there are uncertainties regarding the incremental Utility-sponsored EEassumption. Those uncertainties include:

1. DSM and DR technology innovation and market adoption,2. Future avoided cost projections could change significantly in future years,

thus changing the cost-effectiveness and quantity of EE and DR programs,3. The speed of the Arkansas market’s adoption of building and technology

standards,4. Measure assumptions (e.g. variation in actual EE measure performance),5. DSM and DR program assumptions, and

a. Costs (e.g. program incentive and implementation cost, the marketand policymakers’ tolerance to DSM and DR cost impacts tocustomers’ utility bills)

b. Free-ridership (the portion of the program participants who wouldhave installed the efficient equipment in the absence of theprograms)

c. Participation (e.g. variance in actual market response to EAI’sprograms)

6. General economic uncertainty (e.g. level of new construction,unemployment rates, etc.).

In addition, in the early stages of EAI’s EE programs with the APSC, EAI noted thatnumerous potential projects would be dependent upon the implementation of AMI or

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“smart grid” technology. EAI continues to believe that AMI may provide opportunities toenhance EAI’s EE Portfolio of programs or measures available to its customers. OnceAMI is implemented in EAI’s service area, the programs and measures that can beimplemented in a cost-effective manner may increase.

The energy and peak-reducing impacts of incremental Utility-sponsored EE programsare included in the development of the Sales Forecast. The energy and peakreductions are the same amounts in each of the three IRP load forecast scenarios(Reference, Low and High Cases).

Figure 8 below shows the estimated impacts of existing EAI-sponsored and incrementalEAI-sponsored EE programs to EAI’s peak load forecast. The 2018 IRP only utilizes theload forecast sensitivities that include the impacts of EE.

FIGURE 8: LOAD FORECAST DSM IMPACTS

3. CAPACITY RESOURCE OPTIONS

3.1 GENERATION TECHNOLOGY ASSESSMENT

The IRP process considers a range of alternatives available to meet customer energyneeds in accordance with planning objectives, including supply-side and demand-sidemanagement resource alternatives. As part of this process, a Generation TechnologyAssessment was prepared to identify a wide range of potential supply-side resourcealternatives that merit more detailed analysis due to their potential to meet EAI’splanning objectives of balancing reliability, cost, and risk. Alternatives evaluated (seeFigure 9) are technologically mature and could reasonably be expected to be

4,650

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Loa

d (M

W)

Reference Load No DSM Load

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operational in or around the EAI service territory. Demand-side resources are discussedlater in this section.

FIGURE 9: TECHNOLOGY SCREENING CURVE ILLUSTRATION

TABLE 1: 2018 IRP TECHNOLOGY CATEGORIES

Natural Gas Simple Cycle Combustion Turbine (“CT”)Combined Cycle Gas Turbines (“CCGT”)Aeroderivative CTReciprocating Internal Combustion Engine (“RICE”)

Renewable WindSolar Photovoltaic (“PV”)

Energy Storage Battery Storage

Each of these technologies has relative advantages and disadvantages to consider whendesigning a resource portfolio to meet customers’ energy needs. The information inTable 2 below summarizes some of these considerations.

TABLE 2: GAS-FIRED TECHNOLOGY CONSIDERATIONS

CT CCGT Aeroderivative CT RICE

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Description Frame CTs are a maturetechnology. Low gasprices and continual heatrate and capacityimprovements have madeCTs the industry’stechnology of choice forpeaking applications. CTscan also help integraterenewables by providingquick start (~10 minutes)backup power.

Modern combined cyclefacilities provideefficiencies, moderateflexibility, and improvedCO2 emissions relative tocoal plants, making themsuitable for a variety ofsupply roles (baseload,load-following, limitedpeaking). CCGT efficiencyand flexibility is expectedto continue to improve.

Aeroderivative CTstrade increased costfor greater flexibility(start time, ramptimes), lower heatrates, and higherreliability relative toframe CTs.

RICEs are useful forapplications requiringheavy cycling and ramping,as they incur lower O&Mpenalties when operatedin this manner relative toother conventional peakertechnologies. Asrenewable penetrationincreases, RICEs will likelysee increased deploymentin North American powermarkets due to itsflexibility and efficiency.

Advantages · Low capital and staffingcosts

· Existing operatingexpertise

· Flexible, quick startcapability

· Lowest heat rates· Moderate capital cost· Synergies with existing

and planned fleet (e.g.,parts, staff)

· Higher flexibility· Moderate heat

rates· High reliability

· Low heat rates· Highest flexibility· No gas compression

needed· Modular additions

Disadvantages · Higher heat rates· Difficult to neatly match

need (blocky additions)· High gas pressure

requirements

· Blocky additions· High gas pressure

requirements

· Moderate capitalcost

· High gas pressurerequirements

· Less experiencewith technology

· Moderate capital cost· High variable operating

cost· Less experience with

technology

In addition to the qualitative factors considered above, the table below summarizes themajor inputs from the Generation Technology Assessment for gas-fired generation,which were utilized in the portfolio analyses discussed later in the report.

TABLE 3: GAS-FIRED RESOURCE ASSUMPTIONS

TechnologySummerCapacity

[MW]Capital Cost[2017$/kW]

Fixed O&M[2017$/kW-yr]

Variable O&M[2017$/MWh]

Heat Rate[Btu/kWh]

ExpectedCapacity

Factor [%]

CCGT

1x1 501JAC 510 $1,238 $17.02 $3.14 6,400 80%

2x1 501JAC 1020 $1,090 $11.12 $3.15 6,400 80%

501JAC 300 $833 $2.84 $13.35 9,400 10%

Aero-derivative CT LMS100PA 102 $1,543 $5.86 $2.90 9,397 20%

RICE 7x Wartsila18V50SG 128 $1,642 $31.94 $7.30 8,401 30%

In the last decade, the renewable energy industry has experienced substantial growth,driven in large part by government subsidies and cost declines, technologicalimprovements, and environmental concerns. As shown in Figure 10, solar capital cost

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declines are particularly evident in utility-scale solar installations within the U.S. over thepast five years.12 Among all technologically-feasible renewable energy options, solar andonshore wind resources are the most cost-effective, commercially-available alternativesto meet EAI’s capacity and energy needs.

FIGURE 10: HISTORICAL UTILITY-SCALE SOLAR CAPITAL COSTS

Table 4 below expands upon the relative advantages and disadvantages presented bysolar and wind generation. In general, the advantages of renewable energy resourcesare zero emissions and zero fuel costs (which decreases overall reliance on fuelcommodities), increased diversity within the resource portfolio, and decreased risk forthe benefit of EAI customers. Disadvantages include increased relative land usecompared with traditional alternatives, as well as relative capacity contribution due tothe intermittent nature of these energy sources. The inability to effectively dispatchrenewable resources to meet the changing instantaneous nature of customer usage andthe renewable production curves (e.g., on-peak production versus off-peak production)also affect the value of the resources given EAI’s existing generation portfolio.

TABLE 4: RENEWABLE TECHNOLOGY CONSIDERATIONS

Solar Wind

12 Data adapted from NREL U.S. Solar Photovoltaic System Cost Benchmark, Q1 2017.

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Description Solar capital costs have fallen dramatically in the lastdecade and continue to decline as the industry matures.Solar production roughly aligns with customer loadpatterns, but grid flexibility and quick start backupgeneration are necessary to ensure reliability in theabsence of large-scale, economic energy storagealternatives. The industry will continue to mature andsolar energy is expected to continue to compete withgas-fired generation within the planning horizon,constrained mainly by site-specific performance andmarket conditions (e.g. construction cost, energy value).

The wind industry is mature relative to the solarindustry. Current research focuses more on improvingperformance, rather than cost, through larger, tallerturbines and improved control technologies (e.g.turbine alignment sensors, integrated battery storage).Wind is not likely to see extensive local deploymentwithin the MISO South region, but could play a role inthe region’s energy mix if storage economics improveor significant high voltage direct current (HVDC)projects are completed.

Advantages · Zero emissions· No fuel cost· Capital costs continue to decline· Federal investment tax credits (ITCs)· Predictable energy curve

· Zero emissions· No fuel cost· Federal production tax credits (PTCs)· Efficiency continues to increase

Disadvantages · Capacity value relative to traditional generation· Land-intensive· Integration requirements (responsive, quick start

generation is necessary to integrate large amounts ofsolar PV)

· Site-specific performance· Lack of effective instantaneous dispatch capability

· Capacity value relative to traditional generation· Land-intensive· Integration requirements (responsive, quick start

generation is necessary to integrate large amountsof wind)

· Site-specific performance· Lack of effective instantaneous dispatch capability

Additional unique qualities associated with renewable generation are summarized below.

TABLE 5: ADDITIONAL BENEFITS OF RENEWABLES

Additional Benefits of Renewables

Diversity Renewables add fuel diversity and provide a hedge within gas-centric resource portfolios as EAI’s abilityto rely on coal for fuel diversity becomes uncertain.

Infrastructure Reduced infrastructure requirements (e.g., gas pipelines, water supply) increases siting flexibility.

Scalability Deployment potentially can be scaled up or down to meet capacity needs more easily relative toconventional alternatives, although economics remain a factor.

Carbon Renewables offer customers reduced exposure to potential CO2

costs.

Customer Engagement EAI’s experience with renewables will help meet customer expectations with respect to green tariffofferings, community solar, deployment of distributed energy resources (DERs), and the integration ofAMI.

As shown in Figure 11, the levelized real electricity costs for utility-scale renewables(wind and solar) are expected to decline over the planning horizon, although solar is

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expected to maintain its cost advantage over wind on a $/MWh basis.

FIGURE 11: LEVELIZED REAL COST OF ELECTRICITY FOR RENEWABLES

The table below provides a summary of operational costs and performance assumptionsfor solar and wind technology used within the 2018 IRP.

TABLE 6: RENEWABLE MODELING ASSUMPTIONS

Solar Wind

Fixed O&M (2017$/kW-yr) $16.00 $23.46

Useful Life (yr) 30 25

Capacity Factor 26% 41%

DC:AC 1.35 N/A

Hourly Profile Modeling Software PlantPredict NREL SAM

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Energy storage, particularly in the case of battery-enabled storage, provides a range ofattributes that differ from traditional supply-side options discussed previously, such as:

· the ability to store energy for later commitment and dispatch· ability to discharge in milliseconds and fast ramping capability· rapid construction (on the order of months)· modular deployment providing potential scalability· portability and capability to be redeployed in different areas· small footprint (typically less than an acre), allowing for flexible siting· low round-trip losses compared to other storage technologies (such as

compressed air)

Battery storage system benefits lie in the attributes highlighted above and the ability tooffer stacked values through MISO markets to benefit customers. Battery storageeffectively enables an intra-day temporal shift between energy production and energyuse. Energy can be absorbed and stored during off-peak/low cost hours and dischargedduring on-peak/high cost hours. The spread (i.e., cost difference) between the timeperiods creates cost savings for customers. In addition to energy market attributes,battery storage systems qualify in some markets for various ancillary serviceapplications such as regulation, reserves, and voltage regulation, and qualify for MISO’scapacity market, given sufficient discharge duration. Energy storage, when efficientlyintegrated into the electric grid, can provide transmission benefits by avoidinginvestments required due to line overloads that occur under peak conditions. In additionto these peak-shaving applications, energy storage sited in location-specific areasprovide voltage support, which mitigates the effects of electrical anomalies anddisturbances. Lastly, if paired together, battery storage systems have the potential toshift some solar energy production to late afternoon hours, mitigating the rampingrequirement created by the decline in solar energy production. In addition to theoperational benefit, this can enhance the capacity and energy value of the solar PVinstallation and can lower the battery storage cost through use of the investment taxcredit.

Similar to what has been seen in recent years within the solar industry, it is expectedthat battery storage costs will decline within the planning horizon. Therefore, whilelimited deployment may make sense for EAI customers today, this technology willcontinue to evolve, and additional applications could present themselves in the future.

FIGURE 12: LITHIUM ION BATTERY COSTS

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3.3 POTENTIAL DSM RESOURCE ASSESSMENT

As part of the development of the 2018 IRP, EAI engaged a third-party consultant, ICFInternational, Inc., (“ICF”)13 to quantify potential opportunities for Utility-sponsored DSMprograms to be evaluated as future resource alternatives alongside the supply-sideoptions discussed later in this Section. The potential DSM consists of three DRportfolios and two EE portfolios.

As part of their engagement with EAI, ICF developed Low, Mid, and High DR portfolioswith demand savings targets of 25 MW, 50 MW, and 100 MW, respectively. Theseportfolios consist of a mix of five Residential and Commercial DLC programs and oneCommercial Time-of-Use program (“TOU”). ICF produced hourly demand savings andaccompanying annual program costs for three assumed program start dates: 2020,2025, and 2030. The varying demand savings targets and assumed program start datesyielded nine DR portfolios for economic evaluation in the AURORA model. Note thatthe DR program savings targets build-up; as a result, each of the portfolios aremutually exclusive. The AURORA model cannot select more than one portfolio as aresult.

ICF also developed Low and High EE portfolios based on potential savings from self-direct Industrial customers. Rather than setting specific demand savings targets, ICFmodeled the portfolios based on assumptions around self-direct customer compliancewith APSC EE goals. The Low and High portfolios represent 50% and 25% compliance

13 http://www.icf.com

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with these EE goals, respectively. For example, in the High portfolio ICF’s modelassumes that self-direct customers achieve 25% of their APSC EE target on their own;the remaining 75% represents opportunity for additional demand savings. As with DR,ICF provided the same 2020, 2025, and 2030 program start dates yielding six EEportfolios for evaluation in the AURORA model. The EE program savings associated witheach portfolio build-up and are therefore mutually exclusive.

As described in detail later in this section, these incremental DR and EE portfolios wereincluded in AURORA’s Capacity Expansion Tool for economic selection alongsideexisting supply-side resource options. Each portfolio included an assumed start date,program measure life, hourly demand profile, and annual program costs.

4. ENVIRONMENTAL

Another key driver to changes in future resource needs is the various environmentalregulations that have the potential to affect the long-term viability of EAI’s existinggenerating units. Five key areas of regulations are discussed here: the Regional HazeRule, Cross-State Air Pollution Rule, Coal Combustion Residuals Rule, Effluent LimitationGuideline Rule, and the Affordable Clean Energy Rule. The uncertainty associated witheach area varies. For example, the Regional Haze requirements have been in place forsome time and are far more developed, with greater certainty as to the compliancerequirements and timing. Even so, the specifics that will be required for compliancewith Regional Haze are not known fully at this time.

Regional Haze Rule

The EPA issued a final Federal Implementation Plan (“FIP”) on September 27, 2016, toaddress the requirements of the Regional Haze Rule and visibility transportrequirements for the State of Arkansas that the EPA had previously disapproved. EAIowns three facilities in Arkansas that were subject to the FIP through emissionlimitations that required sulfur dioxide (“SO2”) controls (scrubbers) at the White Bluffand Independence coal-fired plants and oxides of nitrogen (“NOx”) controls (Low-NOx

Burners/Separated Overfire Air) at White Bluff and Independence, and lesser NOx

controls at one natural gas-fired plant, Lake Catherine Unit 4. The final FIP requiredinstallation of the NOx controls at White Bluff and Independence by April 27, 2018, theNOx controls at Lake Catherine Unit 4 by October 27, 2019, and the SO2 controls atWhite Bluff and Independence by October 27, 2021. On March 17, 2018, the 8th Circuitcourt of appeals granted Entergy’s stay motion for the Arkansas Regional Haze FIP.

Following issuance of the final FIP, the ADEQ commenced an effort to develop a StateImplementation Plan (“SIP”) to replace the FIP while still addressing the applicable

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Regional Haze program requirements for the first Regional Haze planning period. TheADEQ SIP process resulted in two separate SIPs, a Phase I SIP which addressed NOx

emissions from electric generating units (“EGUs”), and a second Phase II SIP whichprimarily addressed SO2 emissions.

The Arkansas Phase I SIP was finalized by ADEQ in October 2017 and approved by theEPA on February 12, 2018. This SIP replaced the source-specific FIP NOx limits forWhite Bluff, Independence, and Lake Catherine with an obligation to meet the RegionalHaze program obligations for NOx via compliance with the Cross-State Air PollutionRule (“CSAPR”) ozone-season NOx cap-and-trade program.

The Arkansas Phase II SIP was finalized by ADEQ and transmitted to the EPA for reviewin August 2018. This SIP replaces the source-specific FIP SO2 emission limitations forWhite Bluff and Independence with a requirement that each unit at these plantsachieve SO2 emission reductions via combustion of low-sulfur coal. In addition, the SIPrequires that White Bluff cease to burn coal by December 31, 2028. The SIP alsoacknowledges the assumed planned retirement of Lake Catherine Unit 4 in 2025, whichis consistent with EAI’s 2015 and 2018 IRPs, and EAI’s planning assumption thatIndependence will cease to use coal in 2030. EPA review of this SIP is expected tooccur throughout late 2018 with final EPA action anticipated in early 2019.

Cross-State Air Pollution Rule (CSAPR)

The EPA finalized the CSAPR in 2011 under the “good neighbor” provision of the CleanAir Act to reduce transported pollution that significantly affects downwind non-attainment and maintenance problems for the 2008 ozone National Ambient Air QualityStandard (“NAAQS”). The rule was vacated and stayed December 30, 2011, but in late2014 the stay was lifted following a Supreme Court reversal of the lower courtdecision. Arkansas is subject to CSAPR for ozone-season (May 1 – September 30)emissions of NOx. Affected entities must hold one allowance for every ton of NOX andSO2 generated, depending on which programs their respective state is required toparticipate.

Phase I of CSAPR went into effect in May 2015 and Phase II went into effect in May of2017. On September 7, 2016, the EPA issued a CSAPR update rule which revised theCSAPR program. This 2016 update rule revised the total allowance pool for Arkansassources, including a significant reduction in available allowances beginning with the2018 ozone season.

Coal Combustion Residuals Rule

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In April 2015 the EPA published the final Coal Combustion Residuals (“CCR”) ruleregulating coal ash from coal-fired generating units as non-hazardous wastes underRCRA Subtitle D. The final regulations became effective on October 19, 2015 andcreated new compliance requirements for CCR management including modified storage,new notification and reporting practices, product disposal considerations, ongoingmonitoring requirements and CCR unit closure criteria. In December 2016, the WaterInfrastructure Improvements for the Nation Act (“WIIN Act”) was signed into law, whichauthorizes EPA to enforce the CCR rule rather than leaving primary enforcement tocitizen suit actions. On August 21, 2018, the D.C. Circuit Court vacated and remandedseveral provisions of the CCR rule that relate to inactive and unlined surfaceimpoundments. The CCR rule allows states to seek approval from EPA for state CCRpermit programs. Arkansas has not submitted a CCR permit program proposal to EPAto date.

Entergy operates CCR units at both White Bluff and Independence which are subject tothe CCR rule. Entergy believes that on-site disposal options will continue to beavailable at its facilities, to the extent needed for CCR that cannot be transferred forbeneficial reuse.

Effluent Limitation Guideline Rule

The final Effluent Limitation Guideline rule (“ELG”) was issued by the EPA on November3, 2015. This rule applies to the units at White Bluff and Independence and imposes arequirement that there be zero discharge of bottom ash transport water from the site.This requirement was originally scheduled to become effective between November 1,2018 and December 31, 2023, with the exact date to be determined by the permittingauthority (ADEQ). On September 17, 2017, the EPA finalized a revision to the ELG rulewhich modified the earliest possible compliance date from November 1, 2018 toNovember 1, 2020. In this action, the EPA also indicated intent to reconsider otheraspects of the 2015 ELG rule, including the requirements for bottom ash transportwater.

Clean Power Plan/Affordable Clean Energy Rule

EAI’s Point of View (“POV”), which is based on Entergy’s corporate POV, is that nationalcarbon regulation for the power generation sector will occur; however, the timing,design, and outcome of any carbon control program are highly uncertain. The EPAissued the final Clean Power Plan (“CPP”) on October 23, 2015. The final plan targetedemissions from electric generators utilizing three building blocks (coal plant heat rateimprovements, an increase in dispatch of NGCC units, and an increase sin zero and

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low-emitting generation) to establish state-by-state emission rate limits, expressed interms of lbs. CO2/MWh.

On February 9, 2016, the US Supreme Court issued a stay of the CPP. On March 28,2017, President Trump signed an executive order directing the EPA administrator toreview the CPP. Formal review of the CPP was announced by the EPA on April 4, 2017,and a proposal to repeal the CPP was published by the EPA on October 10, 2017. OnAugust 31, 2018, the EPA published the proposed Affordable Clean Energy (“ACE”) Rule,which is intended to replace the CPP.

The proposed ACE rule would require that each state conduct an analysis of availableheat rate improvements at coal-fired electric generating units. The proposal contains alist of candidate technologies to be included in this review. These technologies are:neural network/intelligent sootblowers, boiler feed pumps, air heater and duct leakagecontrol, variable frequency drives, blade path upgrades (steam turbine), andredesign/replace economizer. In addition, EPA also proposed revisions to the NSRprogram to address potential barriers to implementation of heat rate improvementprojects at generating units.

EAI will monitor the development of the final ACE rule. Once the rule is final, it isanticipated that the ADEQ and/or APSC will conduct a stakeholder process to guideimplementation of the ACE rule in Arkansas. EAI’s participation in the various regulatoryprocesses associated with the ACE rule will, in part, focus on assuring that EAI’scustomers retain the value of the low-greenhouse gas emissions resources for whichthey are and/or have been providing cost-support.

5. FUEL PRICE FORECASTS

5.1 NATURAL GAS PRICE FORECASTS

The near-term portion (year one) of the natural gas price forecast is based on NYMEXHenry Hub forward prices, which are market future prices as of January 2018. Becausethe NYMEX futures market becomes increasingly illiquid as the time horizon increases,NYMEX forward prices are not a reliable predictor of future prices in the long term.Due to this limitation, the long-term point of view regarding future natural gas pricesutilizes a consensus average of several expert independent, third-party consultantforecasts. The long-term natural gas price forecast used in the IRP also includes casesfor high and low gas prices to support analysis across a range of future scenarios. Inlevelized 2018 dollars per MMBtu through the IRP period (2020-2039), the referencecase natural gas price forecast is $3.88, the low case is $2.59, and the high case is

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$5.43. Described in more detail later in this section, each of the IRP Futures assumesthe natural gas price forecast sensitivity appropriate for the future world envisioned.

FIGURE 13: NATURAL GAS PRICE FORECAST AND SENSITIVITIES

5.2 COAL PRICE FORECASTS

The delivered to Entergy coal price forecast is based on a weighted average price ofcoal commodity and coal transportation commitments under contract, as well as third-party consultant forecasts of Powder River Basin coal prices for any open coalcommodity position. In addition, railcar expenses and appropriate plant specific coalhandling cost adders are included. Current transportation rates are escalated by the AllInclusive Less Fuel index and current fuel surcharges are escalated by the diesel fuelprice index. Current plant specific delivery component costs are escalated based on anappropriate index to forecast the future year component cost. In levelized 2018 dollarsper MMBtu through the IRP period (2020-3039), the reference volume weighteddelivered to EAI Coal Price is $2.30. The delivered coal price forecast for non-Entergyplants comes directly from the EVA Forecasts and prices vary by plant.

5.3 CO2 PRICE FORECASTS

EAI’s point of view is that national carbon regulation for the power generation sectorwill occur; however, the timing, design, and outcome of any carbon-control programremain uncertain. The scenarios forecasted and utilized in EAI’s evaluations are basedon the following three cases:

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1. Low Scenario – A $0/ton CO2 price, representing either no program or aprogram that requires “inside-the-fence” measures at generating facilities, suchas efficiency improvements, that do not result in tradable CO2 prices.

2. Reference Scenario – A “CPP Delay” Mid Case representing a regional mass-based cap consistent with achieving the final CPP requirements, but delayed byapproximately 4-6 years due to the federal administration change in 2017 andconsistent with the President’s executive order in March 2017; and,

3. High Scenario – A “National Cap and Trade” High Case assumes a national capand trade program that begins in 2028 and targets an approximately 80 percentreduction from 2005 sector emissions by 2050.

FIGURE 14: CO2 PRICE FORECAST

6. MODELING FRAMEWORK

6.1 FUTURES-BASED APPROACH

In order to reasonably account for a broad range of uncertainty, the 2018 IRP takes afutures-based approach. In this approach, three “futures” were developed that representdifferent combinations of possible outcomes of many variables and reasonably bookendthe range of possible outcomes. Although EAI does not expect the actual future tomaterialize exactly like any of the three modeled futures, the futures-based approachprovides insight to supply needs and indicates the most attractive options to meetthose needs under that future’s particular circumstances. This approach to developingvarious future scenarios is consistent with Section 4.4 of the Commission’s ResourcePlanning Guidelines, which recommends that the planning process identify multiple

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integrated resource portfolios, each of which meets reliability criteria. To further testthe futures, a sensitivity scenario for each future was also modeled to provide insightas to how the optimized portfolios react to changes in assumptions.

Future A – Reference Case

Future A represents a future world which is most closely aligned with the expectedoutcome, or mid-point of the range of uncertainty, of several unknowns. In this future,natural gas prices and future CO2 prices are assumed at the Reference Case levels.The Reference Case Peak Load Forecast is also assumed in Future A.

For EAI’s existing units, CCGTs are assumed to have a 30-year useful life. The WhiteBluff and Independence coal units are assumed to cease using coal by 2028 and2030, respectively.

TABLE 7: FUTURE A ASSUMPTIONS

Future A Key Assumptions(prices shown are 2018$, levelized for the period 2020-39)

White Bluff and Independence Assume the proposed Arkansas Phase II SIPWhite Bluff ceases to use coal in 2028Independence ceases to use coal in 2030

CCGT Units Assume 30-year useful life

Electric Sales & Load Forecasts Reference Case

Henry Hub Natural Gas Price Forecast $3.88/MMBtuCoal Price Forecast $2.30/MMBtu (volume weighted average for EAI units)

CO2Price Forecast $4.15/short ton; pricing begins in 2028

Sensitivity Case Low Case Load ForecastExtend EAI CCGTs through 2039Independence continues using coal through 2039

To supplement the portfolio optimization results from Future A, additional modeling wasperformed as a sensitivity case. For the Future A Sensitivity, the load forecast inputwas changed from Reference Case to the Low Case and the useful life for the CCGT

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units was extended through the end of the IRP evaluation period. Independence wasalso assumed to continue operating as a coal plant through 2039. The Future ASensitivity was designed to reflect more aggressive underlying trends in customer usagepatterns and organic energy efficiency penetration as well as acknowledge that existinggeneration may reliably operate beyond the technology-specific useful life assumptionsused for the purposes of the IRP.

Future B – Low Supply Additions Case

Future B represents a future world in which the need and economics for new supplyadditions are depressed. In this future, natural gas prices, as shown in Figure 13, areassumed at Low case level. Coal prices are assumed at Reference levels given that EAIprocures coal via plant-specific contracts, which reduces associated market pricevariability. The Low Case for CO2 does not assume any price for carbon emissionsover the entire study period. The Low Case Load Forecast is assumed in Future B,which reduces EAI’s need for future supply additions.

Assumptions for EAI’s existing units align with Future A; existing CCGT units wereassumed at a 30-year useful life and White Bluff and Independence are assumed tocease using coal in 2028 and 2030, respectively.

TABLE 8: FUTURE B ASSUMPTIONS

Future B Key Assumptions(prices shown are 2018$, levelized for the period 2020-39)


CCGT Units Assume 30-year useful lifeElectric Sales & Load Forecasts Low Case

Henry Hub Natural Gas Price Forecast $2.59/MMBtuCoal Price Forecast $2.30/MMBtu (volume weighted average for EAI units)CO2 Price Forecast No price for CO2 throughout IRP study periodSensitivity Case Reference Case Load Forecast

Extend EAI CCGTs through 2039Independence continues using coal through 2039

Additional portfolio optimization modeling was also completed for Future B as asensitivity case. Complementary to the Future A Sensitivity, for the Future B Sensitivitythe load forecast input was changed from Low Case to Reference Case. Also, theuseful life for the CCGT units was extended through the end of the IRP evaluationperiod. Independence was also assumed to continue operating through 2039. The

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Future B Sensitivity models a future scenario that effectively extends the current statusquo, i.e. persistent low gas prices and energy growth that reflects current trends incustomer usage and energy efficiency penetration.

Future C – High Supply Additions Case

Future C represents a future world in which the need and economics for new supplyadditions are enhanced. In this future, natural gas prices are assumed at the HighCase levels. As noted in Future B, delivered coal prices are assumed at the Referencelevel. The High Case price for CO2 is also assumed, which begins in 2028 as in FutureA, but at a higher price. The High Case Load Forecast is assumed in Future C, whichincreases EAI’s need for future supply additions.

Assumptions for EAI’s existing units align with Futures A and B; existing CCGT unitswere assumed at a 30-year useful life and White Bluff and Independence are assumedto cease using coal in 2028 and 2030, respectively.

TABLE 9: FUTURE C ASSUMPTIONS

Future C Key Assumptions(prices shown are 2018$, levelized for the period 2020-39)


CCGT Units Assume 30-year useful lifeElectric Sales & Load Forecasts High CaseHenry Hub Natural Gas Price Forecast $5.43/MMBtuCoal Price Forecast $2.30/MMBtu (volume weighted average for EAI units)CO2 Price Forecast $14.50/short ton; pricing begins in 2028Sensitivity Case Modified Load Growth Load Forecast

As with Futures A and B, a portfolio optimization sensitivity was developed for Future Cto supplement the baseline portfolio results. The Future C Sensitivity explores how theportfolio of resources changes in response to higher levels of customer investment inrooftop solar or other AMI-enabled activities that reduce usage during traditional peakhours.The load forecast input was changed from High Case to Modified Load Growth (“MLG”),which was developed specifically for Future C’s Sensitivity case using modified DR loadshapes produced by ICF. As in Future C, the Sensitivity case assumes high natural gasand environmental costs which yield higher energy costs versus Futures A and B. TheMLG forecast envisions a future where EAI’s customers are enabled by AMI technologyand have a greater economic incentive to adapt their energy consumption given higher

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relative energy prices. One example of how the Future C Sensitivity could develop isthrough significant increases in customer investment in rooftop solar or other types ofdistributed generation.

DR load shapes were decremented from the Reference Load forecast to produce theMLG load forecast. The resulting forecast primarily shifts customer energy usage awayfrom peak hours and into off-peak hours, when energy is less expensive. As a result,annual peak loads are -1.0% to -2.3% lower versus the Reference Load forecast.

6.2 IRP MODELING OVERVIEW

The development of the 2018 IRP relied on the AURORA14 Energy Market Model togenerate market prices (Locational Marginal prices or LMPs) for the MISO energymarket and develop optimized portfolios for EAI under a range of possible futures.AURORA is a production cost and capacity expansion optimization tool that simulatesenergy market operations using hourly demands and individual resource operatingcharacteristics in a chronological dispatch algorithm and uses projected marketeconomics to determine the optimal long-term resource portfolio under varying futureconditions including fuel prices, available generation technologies, available DSMprogram alternatives, environmental constraints, and future demand forecasts.AURORA’s optimization process identifies the set of future resources that economicallymeets the identified requirements given the defined constraints.

6.3 MARKET MODELING

The first step in the IRP modeling process is to utilize AURORA to develop a projectionof the MISO market energy price and operations based on the specific characteristicsof each future. The energy market simulation results in hourly energy prices for eachof the three futures. The projection encompasses the power market for the entire MISOfootprint, excluding EAI. MISO-South (excluding EAI) projected power prices are used toassess potential portfolio strategies for EAI in each future during the capacityexpansion optimization step. The scope of the markets modeled in this step is shownin Appendix D.

FIGURE 15: AVERAGE ANNUAL MISO SOUTH NON-EAI LMP

14 The AURORA Model is the primary production cost tool used to perform MISO energy market modeling and long-termvariable supply cost planning for EAI. AURORA supports a variety of resource planning activities and is well suited forscenario modeling through hourly simulation of the MISO market. It is widely used by a range of organizations,including large investor-owned utilities, small publically-owned utilities, and regulators.

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6.4 EAI PORTFOLIO OPTIMIZATION

Following the market modeling process, which results in LMPs for the MISO Southregion excluding EAI, the AURORA long-term capacity expansion logic was used toselect resources to meet EAI’s future capacity needs. Each of the three futures wasmodeled in AURORA and the capacity expansion logic was utilized to determine thetiming, amount, and type of incremental capacity and incremental DSM to be added toEAI’s existing portfolio to meet EAI’s reliability requirements (target planning reservemargin requirements), subject to constraints, under each future. This step resulted in a20-year resource expansion plan which is economically optimized to meet EAI’sforecasted demand under each future scenario.

For the 2018 IRP, EAI sought to take into account capacity credit considerations ofnon-dispatchable, intermittent generation that is provided by solar and wind resources.As the amount of installed renewable resources in the generation portfolio increases,the contribution of an individual renewable resource towards meeting the planningreserve margin may decrease. This is due to solar production potentially shifting aload serving entity’s net peak (demand less solar), such that every incremental unit ofsolar provides less value in supporting reliability needs. The concept that solar providesdiminishing returns in capacity and energy value has been further explored in works byCAISO15 and MISO16 to great detail.

15 https://www.nrel.gov/docs/fy16osti/65023.pdf16 https://cdn.misoenergy.org/20180605%20RIIA%20Workshop%20Presentation213125.pdf

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To account for the diminishing value of non-dispatchable, intermittent resources, EAIused functionality within the AURORA model that considers the impact of solar andwind on the peak load when selecting resources to include in the optimized portfolios.As a result, the capacity contribution of solar and wind within the optimized portfoliosis dependent on the amount of incremental solar and wind added, the productionprofiles of these resources, and the load shape of EAI’s customers. The diminishingreturns of solar and wind resource additions are accounted for in the AURORAcapacity expansion; for the purposes of computing a total supply cost to customers,EAI defaulted to the current MISO practice for new resources without sufficientoperating history – 50% capacity credit for solar and 15.6% capacity credit for wind.

6.5 2018 EAI IRP DSM MODELING

Potential DSM Programs were evaluated as resource alternatives alongside supply sideresource alternatives in the AURORA capacity expansion optimization in order toidentify the most economic combination of DSM programs and supply side resourcesthat meet EAI’s customer needs subject to constraints.

Potential DSM programs were evaluated based on the characteristics and attributesdescribed in earlier in this section. Each DSM program was modeled in AURORA basedon annual program costs, hourly demand reduction profiles, program start date(s),assumed program life, and program dependencies or mutually exclusive restrictions andevaluated to identify the DSM programs that are economic (i.e. have a positive netbenefit). The following potential DSM programs were modeled, totaling 15 potentialalternatives:

· DR resource alternatives included three mutually exclusive DR portfolios (low,mid, high) with three discrete start year options (2020, 2025, 2030). Refer toFigure 16.

· EE resource alternatives included two mutually exclusive EE portfolios (low, high)with 3 discrete start year options (2020, 2025, 2030). Refer to Figure 17.

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FIGURE 16: DR RESOURCE ALTERNATIVES

FIGURE 17: EE RESOURCE ALTERNATIVES

AURORA considers the cost and revenue of energy and capacity in the context of theMISO market for each supply side alternative and each DSM alternative. Selection ofDSM alternatives in the model was based strictly on economics in order to avoid non-selection due to a lack of capacity need in the discrete start year options. Thecapacity credit of selected DSM programs is counted toward meeting EAI’s capacityneeds through reduction of peak load.

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7. RESULTS

7.1 FUTURE A RESULTS

A total of 6,660 MW of installed capacity is added to EAI’s resource portfolio in FutureA. On an effective capacity basis, which accounts for the intermittency of solar andwind resources, the total capacity addition is 5,545 MW (excluding DSM). The firstresource added is the Low EE 2020 portfolio from the Potential DSM Resources. Thefirst generation capacity is added in 2025 and consists of one CT unit; note that thesolar capacity additions illustrated in Figure 18 below did not originate from AURORA’scapacity expansion model (these resources are discussed in Section II). Overall, 68% ofthe modeled supply additions are natural gas resources while the remaining 32% arefrom renewable resources. The total relevant supply cost17 for the Future A optimizedportfolio is $9,050 million (2020-2039 present value, 2020$MM).

FIGURE 18: FUTURE A SUPPLY ADDITIONS

The portfolio mix of capacity resources over the 20-year IRP study period is shownbelow, followed by the fuel diversity based on energy generated for the Future Aportfolio. The energy mix shown includes energy used to meet native load need andsales to the market.

17 The total relevant supply cost consists of the sum of two components: the variable supply cost for the entireportfolio (existing, planned and incremental resources added via AURORA optimization) plus the fixed cost componentsof the incremental resources added via AURORA optimization and any other future fixed costs of existing resources thatvary among the futures.

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FIGURE 19: FUTURE A CAPACITY MIX

FIGURE 20: FUTURE A ENERGY MIX

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7.2 FUTURE B RESULTS

A total of 4,984 MW of installed capacity is added to EAI’s resource portfolio in FutureB. On an effective capacity basis, which accounts for the intermittency of solar andwind resources, the total capacity addition is 4,825 MW (excluding DSM). The firstresource added is the Low EE 2020 portfolio from the Potential DSM Resources. Thefirst generation capacity is added in 2025 and consists of 100 MW of solar; as inFuture A, note that the solar capacity additions illustrated in Figure 21 below did notoriginate from AURORA’s capacity expansion model. Overall, 94% of the modeledsupply additions are natural gas resources while the remaining 6% are from renewableresources. The total relevant supply cost for the Future B optimized portfolio is $6,673million (2020-2039 present value, 2020$MM).

FIGURE 21: FUTURE B SUPPLY ADDITIONS

The portfolio mix of capacity resources over the 20-year IRP study period is shownbelow, followed by the fuel diversity based on energy generated for the Future Bportfolio. The energy mix shown includes energy used to meet native load need andsales to the market.

FIGURE 22: FUTURE B CAPACITY MIX

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FIGURE 23: FUTURE B ENERGY MIX

7.3 FUTURE C RESULTS

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A total of 7,128 MW of installed capacity is added to EAI’s resource portfolio in FutureC. On an effective capacity basis, which accounts for the intermittency of solar andwind resources, the total capacity addition is 5,739 MW (excluding DSM). The firstresource added is the High EE 2020 portfolio from the Potential DSM Resources. Thefirst generation capacity is added in 2025 and consists of one CT unit and 200 MW ofwind; as in Futures A and B, note that the solar capacity additions illustrated in Figure24 below did not originate from AURORA’s capacity expansion model. Overall, 68% ofthe modeled supply additions are natural gas resources while the remaining 32% arefrom renewable resources. The total relevant supply cost for the Future C optimizedportfolio is $10,416 million (2020-2039 present value, 2020$MM).

FIGURE 24: FUTURE C SUPPLY ADDITIONS

The portfolio mix of capacity resources over the 20-year IRP study period is shownbelow, followed by the fuel diversity based on energy generated for the Future Cportfolio. The energy mix shown includes energy used to meet native load need andsales to the market.

FIGURE 25: FUTURE C CAPACITY MIX

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FIGURE 26: FUTURE C ENERGY MIX

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7.4 FUTURE A SENSITIVITY RESULTS

A total of 5,866 MW of installed capacity is added to EAI’s resource portfolio in theFuture A Sensitivity. On an effective capacity basis, which accounts for theintermittency of solar and wind resources, the total capacity addition is 3,756 MW(excluding DSM). The first resource added is the Low EE 2020 portfolio from thePotential DSM Resources. The first generation capacity is added in 2025 and consistsof a 100 MW battery; note that the solar capacity additions illustrated in Figure 27below did not originate from AURORA’s capacity expansion model. Overall, 42% of themodeled supply additions are natural gas resources while the remaining 58% are fromrenewable resources. The total relevant supply cost for the Future A Sensitivityoptimized portfolio is $7,556 million (2020-2039 present value, 2020$MM).

FIGURE 27: FUTURE A SENSITIVITY SUPPLY ADDITIONS

The portfolio mix of capacity resources over the 20-year IRP study period is shownbelow, followed by the fuel diversity based on energy generated for the Future ASensitivity portfolio. The energy mix shown includes energy used to meet native loadneed and sales to the market.

FIGURE 28: FUTURE A SENSITIVITY CAPACITY MIX

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FIGURE 29: FUTURE A SENSITIVITY ENERGY MIX

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7.5 FUTURE B SENSITIVITY RESULTS

A total of 3,180 MW of installed capacity is added to EAI’s resource portfolio in theFuture B Sensitivity. On an effective capacity basis, which accounts for theintermittency of solar and wind resources, the total capacity addition is 3,071 MW(excluding DSM). The first resource added is the Low EE 2020 portfolio from thePotential DSM Resources. The first generation capacity is added in 2025 and consistsof one CT unit; note that the solar capacity additions illustrated in Figure 30 below didnot originate from AURORA’s capacity expansion model. Overall, 94% of the modeledsupply additions are natural gas resources while the remaining 6% are from renewableresources. The total relevant supply cost for the Future B Sensitivity optimized portfoliois $7,064 million (2020-2039 present value, 2020$MM).

FIGURE 30: FUTURE B SENSITIVITY SUPPLY ADDITIONS

The portfolio mix of capacity resources over the 20-year IRP study period is shownbelow, followed by the fuel diversity based on energy generated for the Future BSensitivity portfolio. The energy mix shown includes energy used to meet native loadneed and sales to the market.

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FIGURE 31: FUTURE B SENSITIVITY CAPACITY MIX

FIGURE 32: FUTURE B SENSITIVITY ENERGY MIX

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7.6 FUTURE C SENSITIVITY RESULTS

A total of 7,181 MW of installed capacity is added to EAI’s resource portfolio in theFuture C Sensitivity. On an effective capacity basis, which accounts for theintermittency of solar and wind resources, the total capacity addition is 5,485 MW(excluding DSM). The first resource added is the High EE 2020 portfolio from thePotential DSM Resources. The first generation capacity is added in 2025 and consistsof a 1x1 CCGT paired with 200 MW of wind; note that the solar capacity additionsillustrated in Figure 33 below did not originate from AURORA’s capacity expansionmodel. Overall, 66% of the modeled supply additions are natural gas resources whilethe remaining 34% are from renewable resources. The total relevant supply cost forthe Future C Sensitivity optimized portfolio is $9,228 million (2020-2039 present value,2020$MM).

FIGURE 33: FUTURE C SENSITIVITY SUPPLY ADDITIONS

The portfolio mix of capacity resources over the 20-year IRP study period is shownbelow, followed by the fuel diversity based on energy generated for the Future CSensitivity portfolio. The energy mix shown includes energy used to meet native loadneed and sales to the market.

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FIGURE 34: FUTURE C SENSITIVITY CAPACITY MIX

FIGURE 35: FUTURE C SENSITIVITY ENERGY MIX

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IV. ACTION PLAN

1. FINDINGS AND CONCLUSIONS

1.1 SUMMARY OF FINDINGS

As discussed above, the AURORA Portfolio Optimization process resulted in six distinctresource portfolios, each of which are economically optimal for the respective future orsensitivity cases. When reviewing the results of those distinct resource portfolios, themany varying inputs across the futures must be taken into consideration. Because itwas necessary to capture a broad range of uncertainties in the IRP Futures in order tobookend the range of possible outcomes, caution must be taken when comparingresults between the futures. Nevertheless, the table below summarizes the results ofthe Portfolio Optimization for each future.

TABLE 10: SUMMARY OF MODELING RESULTS

2020-39 Modeling Results Future A Future B Future C

Total Incremental Installed Capacity: 6,660 MW 4,984 MW 7,128 MW

Natural Gas Capacity Additions: 68.4% 94.0% 67.5%

Renewable Capacity Additions: 31.6% 6.0% 32.5%

DSM Capacity Additions: 2020 Low EE 2020 Low EE 2020 High EE

Incremental Generation Capacity Additions Begin: 2025 2025 2025

Incremental Generation Capacity Type: CT Solar CT + Wind

The optimal portfolio is consistent across the futures. Future C adds morecapacity overall than Future A, but the fuel mix is similar. Future B has the smallestneed for incremental capacity additions and assumptions that favor gas-fired resources,so the resulting portfolio mix is different from the others but is reasonable for that setof assumptions. Overall, the indication is that both renewable and gas-fired resourcesare cost-effective in the future. The result also affirms the current resource planningprotocol of gradually adding cost-effective renewables and monitoring the resourceneeds as well as external market factors for the appropriate time to add other typesof resources.

Renewables have become more cost-effective. As a percentage of incrementalresource additions, renewables have increased across all futures since the 2015 IRP.While the increase in the ratios may appear modest, this is even more significant giventhat the natural gas price forecast has decreased almost 30% since the 2015 IRP. As

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discussed in the prior section, the 2018 IRP modeling also used functionality within theAURORA model that considers the impact of solar and wind on the peak load whenselecting resources to include in the optimized portfolios.

TABLE 11: GAS TO RENEWABLES COMPARISON

Gas to Renewables Ratios 2015 IRP 2018 IRP

Low Case Ratio: 100% / 0% 94% / 6%

Reference Case Ratio: 73% / 27% 68% / 32%

High Case Ratio: 73% / 27% 68% / 32%

Generation is added in 2025 across all futures and sensitivities. The firstgeneration resource addition in each of the three futures, as well as each of the threesensitivities, is added in 2025, though the technology type and size varies ranging froma 100 MW solar resource to 732 MW of combined CT and wind resources. Sinceresources are added in all futures, including Future B which assumes the Low LoadForecast, this is primarily driven by the deactivation assumption used in the 2018 IRPmodel for Lake Catherine Unit 4. Also, the recent actions EAI has taken by adding twosolar PPAs and issuing a third RFP for solar resources over the past four years havepartially mitigated the 2025 capacity need depending on how customer loadrequirements change over the next few years.

A CCGT is added in 2028 across all futures and most sensitivities. The nextcommon theme across the 2018 IRP portfolios is that a CCGT resource is consistentlyadded in 2028. The exception is Future C, which adds a CCGT resource in 2027 and asimilar amount of renewable capacity in 2028. While EAI saw in its 2015 IRP and hasseen in this 2018 IRP that the optimal resource portfolio of the future is likelycomprised of a combination of renewables and conventional resources, the potential2028 capacity need (created by the need to replace the coal-fired energy from WhiteBluff) may need to be primarily addressed by gas-fired, i.e. non-intermittent, generationthat can serve the energy requirements of EAI customers.

A demand-side resource alternative is cost-effective in all scenarios. Specifically,varying levels of potential energy efficiency is selected in each portfolio. On the otherhand, none of the demand response programs were selected. This result indicates thatopportunity may exist for EAI to explore potential cost-effective energy efficiencyinvestments as part of its future portfolio of resources.

2. ACTION PLAN

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As was concluded in the 2015 IRP, the 2018 IRP continues to support the conclusionthat EAI’s future supply-side resource additions will likely consist of a mix of naturalgas fired resources and renewable energy resources. Based on the work conducted aspart of the 2018 IRP analysis, it is also reasonable to conclude that demand-sideresources will continue to be a component of the capacity portfolio. The amount oftotal capacity that will be needed and exactly when that capacity will be needed areuncertain. There is even more uncertainty associated with exactly how much of eachsupply-side technology should be added to EAI’s fleet and exactly how to identifypotential demand-side resources. Because of those uncertainties, EAI will not establishspecific targets for renewable generation or traditional generation as part of this IRPanalysis. Rather, EAI will take deliberate steps in its Integrated Resource Planning at theappropriate time based on all the relevant information available at that time. Forexample, supply-side resource additions will be made based on specific projectproposals.

The action items below represent a pragmatic approach to EAI’s integrated planningover the coming three years. By necessity, the integrated planning process issubdivided into work streams, each with their own process and timeline.

2018 IRP ACTION PLAN

1. Complete theBuild-Own-Transfer ofSolar PV

As a result of EAI’s 2017 Request for Proposals for Build-Own-Transfer Solar Resources, EAI is currently working toward executingagreements for additional solar generation. Assuming requiredregulatory approvals are received, the acquisition of additional solarPV generation is expected to take place in 2021.

2. Supply-sideResourceAdditions

EAI will monitor its load and capability position and take steps toadd supply side resources for both traditional and/or renewableresources as warranted. Based on current information, a competitivesolicitation may be issued in 2019 for long-term resources. Inaddition to market solicitation, EAI will be considering developingself-build proposals for certain supply side technologies. However,the exact scope and timing of the next EAI RFP is uncertain and isdependent on many factors noted throughout this report.

3. Potential2025 CapacityNeed

EAI will complete an evaluation of the availability and economics ofLake Catherine Unit 4 past the assumed deactivation date of 2025.In combination with Action Item #2 above, EAI will update the loadand capability position in order to monitor the capacity need in2025.

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4. Demand-sideResourceOpportunities

EAI will seek and evaluate cost-effectiveness and feasibility forpotential projects or programs to gain energy efficiencies inaddition to its existing Arkansas Energy Efficiency Program Portfolio.For example, this may be achieved through EE programs with Self-Direct customers or, after implementation of AMI, through AMI-enabled programs or distributed generation resources.

5. ContinueParticipation inEE

EAI will continue to offer cost effective EE and DR programs withinthe Commission’s Rules for Conservation and Energy EfficiencyPrograms and subsequent future Commission orders as providedthrough Arkansas State law, including the recently increased targetsthat were not available at the time of the 2018 IRP study18. Finally,EAI is committed to update the IRP in 2021 and will include anupdate to the future outlook for DSM as well.

6. CoalEnvironmentalCompliance

The challenge utilities face with regards to environmental complianceis unprecedented in terms of the number of recent and upcomingrules which affect utilities, the compressed time frame forcompliance, and the continuing ratcheting down of complianceobligations. Key uncertainties include the requirements related toRegional Haze, ambient air quality standards, coal combustionresiduals regulation, effluent limitation guidelines, among others, theoutcome of current litigation, congressional activity and thepossibility of extensions of compliance deadlines. Another keyuncertainty is the nation’s long-term carbon policy. The industryneeds a satisfactory resolution of both the current regulatorychallenges and a long-term legislative solution on carbon. EAI willcontinue to monitor changes in environmental law and regulationsat the state and federal level and evaluate options forenvironmental compliance for the EAI coal units.

7. StakeholderEngagementProcess

Stakeholder engagement has been an important part of thedevelopment of this IRP. An immediate priority will be for EAI toclosely review the stakeholder report, which can be found inAppendix E of this report, and take steps to address concerns andsuggestions.

18 Order 43 in Docket No. 13-002-U, effective July 13, 2018

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V. STAKEHOLDER ENGAGEMENT

Per the APSC Resource Planning Guidelines,19 one part of the development of the IRP isto engage with all of the stakeholders in EAI’s long-term planning process. Stakeholdersinclude representatives of retail and wholesale customers, independent power suppliers,marketers, and other interested entities in EAI’s service area.

For the 2018 IRP, the Stakeholder Engagement Process began in May 2018 withdistribution of a detailed slide presentation describing proposed assumptions, inputs,and modeling framework. The materials, while still preliminary, were posted to EAI’s IRPwebsite20. Additional meeting materials, which included preliminary modeling results fromall three Futures, were provided to stakeholders in advance of the in-personstakeholder meeting hosted by EAI in June 2018.

As noted, EAI hosted an in-person meeting at the MISO South building in Little Rockon June 6, 2018. During the June 6th meeting, presentations were given by several EAIrepresentatives covering a broad range of inputs and modeling results for the IRP. TheCompany received questions and feedback both during and subsequent to the meeting.Additionally, the stakeholders organized into a Stakeholder Committee during the June6th meeting.

Both during and subsequent to the June 6th meeting, over 100 detailed questions weresubmitted to EAI by various stakeholders, to which EAI responded via follow-up postingsto the IRP website. EAI’s responses were posted in four subsets in order to provideresponses as quickly as possible, with most responses posted within a week of receipt.A notification was sent to stakeholders via email at the time of each posting.

At the request of the Stakeholder Committee, EAI hosted a conference call in August2018 to have a technical discussion of the Committee’s feedback regarding EAI’s IRPmodeling. During the call, EAI offered to provide additional modeling scenarios basedon requested assumptions from the Stakeholder Committee. No additional requestsfrom the Stakeholder Committee were presented at that time or following theconference call. Finalized portfolio optimization modeling results for all Futures andSensitivities were posted by EAI to the IRP website on October 4, 2018. TheStakeholder Committee requested additional time to complete the Stakeholder Report,which was provided to EAI on October 24, 2018. As described in Item 7 of the 2018IRP Action Plan, EAI will closely review the Stakeholder Report and incorporate

19 Docket No. 06-028-R, Order No. 6, Attachment 120 http://www.entergy-arkansas.com/integrated_resource_planning

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feedback as EAI executes the 2018 IRP Action Plan and prepares for the next IRPcycle.

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APPENDIX A – RESOURCE PLANNING OBJECTIVES

PURPOSE:

The purpose of this document is to establish resource planning objectivesto guide Entergy Arkansas, Inc. (EAI) resource planning and operations staff indevelopment of EAI’s Integrated Resource Plan (IRP) and to meet the requirements ofthe APSC Resource Planning Guidelines for Electric Utilities.

OBJECTIVES:

In developing EAI’s IRP, EAI’s resource planning and operations staff should considerthe following resource planning objectives:

1. Policy Objectives – The development of the IRP should reflectpolicy and planning objectives reviewed by the EAI RPOC andapproved by EAI’s President and Chief Executive Officer. Thosepolicy and planning objectives will consider and reflect the policyobjectives and other requirements provided by EAI’s regulators.

2. Resource Planning – The development of the IRP will considergeneration, transmission, and demand-side (e.g., demandresponse, energy efficiency) options.

3. Planning for Uncertainty – The development of the IRP willconsider scenarios that reflect the inherent unknowns anduncertainties regarding the future operating and regulatoryenvironments applicable to electric supply planning including thepotential for changes in statutory requirements.

4. Reliability – The IRP should provide adequate resources to meetEAI’s customer demands and expected contingency events inkeeping with established reliability standards.

5. Baseload Production Costs – The IRP should provide baseloadresources that provide stable long-term production costs and lowoperating costs to serve baseload energy requirements.

6. Operational Flexibility for Load Following – The IRP shouldprovide efficient, dispatchable, load-following generation and fuelsupply resources to serve the operational needs associated withelectric system operations and the time-varying load shape levels

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that are above the baseload supply requirement. Further the IRPshould provide sufficient flexible capability to provide ancillaryservices such as regulation, contingency and operating reserves,ramping, and voltage support.

7. Generation Portfolio Enhancement – The IRP should provide ageneration portfolio that over time will realize the efficiency andemissions benefits of technology improvements and that avoidsan over-reliance on aging resources.

8. Price Stability Risk Mitigation – The IRP should consider factorscontributing to price volatility and should seek to mitigateunreasonable exposure to the price volatility associated with themajor uncertainties in fuel and purchased power costs.

9. Supply Diversity and Supply Risk Mitigation – The IRP shouldconsider and seek to mitigate the risk exposure to major supplydisruptions such as outages at a single generation facility or thesource of fuel supply.

10. Locational Considerations - The IRP should consider theuncertainty and risks associated with dependence on remotegeneration and its location relative to EAI’s load so as toenhance the certainty associated with the resource’s ability toprovide deliver power to EAI’s customers.

11. Reliance on Long-Term Resources – EAI will meet reliabilityrequirements primarily through long-term resources, both ownedassets and long-term power purchase agreements. While areasonable utilization of short-term purchased power isanticipated, the emphasis on long-term resources is to mitigateexposure to supply replacement risks and price volatility, andensure the availability of resources sufficient to meet long-termreliability and operational needs. Over-reliance on limited-termpurchased power (i.e., power purchased for a one to five yearterm) exposes customers to risk associated with market pricevolatility and power availability.

12. Sustainable Development – The IRP should be developedconsistent with EAI’s vision to conduct its business in a mannerthat is environmentally, socially and economically sustainable.

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APPENDIX B - EAI PORTFOLIO OF RESOURCES

Owned Generation Total InstalledCapacity(MW)

Ownership(%)

RetailCapacity(MW)

CommercialOperations

Date

Arkansas Nuclear OneUnit 1

834 100% 789 1974

Arkansas Nuclear OneUnit 2

986 100% 933 1980

Carpenter Unit 1 31 100% 31 1932

Carpenter Unit 2 31 100% 31 1932

Hot Spring 606 100% 606 2002

Independence Unit 1 839 31.5% 221 1983

Lake Catherine Unit 4 528 100% 528 1970

Ouachita Unit 1 252 100% 252 2002

Ouachita Unit 2 253 100% 253 2002

Remmel Units 1, 2 & 3 12 100% 12 1925

Union 2 501 100% 501 2003

White Bluff Unit 1 815 57.0% 401 1980

White Bluff Unit 2 822 57.0% 402 1981

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Purchased Generation Total InstalledCapacity(MW)

RetailCapacity(MW)

CommercialOperations

Date

Blakely 86 11 1956

DeGray 78 10 1972

Grand Gulf 1,409 308 1985

Stuttgart Solar 81 81 2017

Notes: - Blakely and DeGray capacity is assumed through 5/31/2019 - Grand Gulf Capacity is assumed through the IRP study horizon. - Stuttgart Solar achieved commercial operations in December 2017;

EAI’s PPA began effective 6/1/2018.

Demand-side Resources Reduction DuringPeak Load Hours (MW)

Demand Response 59

Interruptible Load 57

Notes: - Estimates above are 2018 reductions. - EAI’s Demand Response includes Residential Direct Load Control

and Agricultural Irrigation Load Control programs. - Demand Response and Interruptible capacity is grossed up to account for reserve margin and line loss value in the Load &

Capability analysis.

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APPENDIX C - MISO MTEP SUBMISSIONS

TABLE 12: EAI PROJECTS APPROVED IN APPENDIX A OF MTEP17

Project Driver Project Name CurrentProjected ISD

Load Growth LR Kanis: Install 3rd distribution transformer(necessitates station conversion to breaker

and a half configuration)

Complete

Load Growth Greyhawk 161 kV: New DistributionSubstation

6/1/2020

Load Growth Tarleton 230 kV: New Distribution Substation 6/1/2019

Load Growth MacArthur 115 kV: New DistributionSubstation

11/1/2019

Load Growth Pecan Street 161 kV: New DistributionSubstation

11/15/2019

Load Growth Big Creek 115 kV: New Distribution Substation 5/1/2020

Load Growth Russellville Industrial 161 kV: New DistributionSubstation

12/1/2019

Transmission Reliability - MeetingPlanning Criteria

Jacksonville North - Sylvan Hills 115 kV:Upgrade line bay bus at Sylvan Hills

12/1/2018


El Dorado Donan 115 kV: Install 30MVARcapacitor bank

Complete


Independence: Replace 500/161 kV Autos 12/1/2019


West Helena: Install 115 kV breakers 12/1/2019


Russellville East 161 kV: Install 10 Ohm SeriesReactor

6/1/2020


Happy Valley - Hot Springs 500 kV Project 6/1/2024

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TABLE 13: EAI PROJECTS SUBMITTED AS TARGET APPENDIX A IN MTEP18

Project Driver Project Name CurrentProjected ISD

Asset Management Moses 161 kV: New Substation 6/1/2019

Load Growth Sierra 115 kV: New Distribution Substation 5/1/2020

Load Growth Skunk Hollow 161 kV: New DistributionSubstation

6/1/2021

Load Growth Social Hill 115 kV: New Distribution Substation 6/1/2021

Load Growth Palestine 161 kV: New Distribution Substation 6/1/2023


Jacksonville North - Holland Bottom 115 kV:Upgrade line to 100 C operation

12/1/2019


Cheetah - Hot Springs Village 115 kV: Rebuildline

12/1/2020


Conway S. - Conway Ind. 161 kV: Rebuild line 12/1/2020


Camden Maguire - Smackover 115 kV: Rebuildline

6/1/2021


Paragould 161/115 kV: Install station serviceto enable autotransformer cooling pumps and

uprate autotransformer.

12/1/2021


Fourche - Little Rock East 115 kV: Rebuild line 6/1/2021


Hilltop - St Joe 161 kV: Rebuild line 6/1/2023


St Joe - Everton Road 161 kV: Rebuild line 12/1/2024


Everton Road - Harrison East 161 kV: Rebuildline

6/1/2025


Southland - Mt Home 161 kV: Rebuild line 12/1/2023


Norfork - Southland 161 kV: Rebuild line 12/1/2027

Transmission Service Mabelvale 500 kV: Switch Replacement 11/1/2018

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TABLE 14: EAI PROJECTS TO BE SUBMITTED AS TARGET APPENDIX A IN MTEP19

Project Driver Project Name CurrentProjected

ISDTransmission Reliability - Meeting

Planning CriteriaHot Springs Village – Sierra 115kV Rebuild 6/1/2021

Transmission Enhanced Reliability Little Rock Area Enhanced Reliability – Phase 1Rebuild L.R. Gaines – L.R. 8th & Woodrow 115kV

12/1/2021

Transmission Enhanced Reliability Little Rock Area Enhanced Reliability – Phase 2Rebuild L.R. 8th & Woodrow – L.R. Palm Street –

L.R. West 115kV

12/1/2022

Transmission Enhanced Reliability Amity Tap 115kV Construct Breaker Station 6/1/2024

Transmission Enhanced Reliability Batesville 161kV Install Breakers 6/1/2024

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APPENDIX D – SCOPE OF AURORA MARKET MODEL

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APPENDIX E – STAKEHOLDER REPORT

[ATTACHMENT]

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STAKEHOLDER COMMENTS REGARDING ENTERGY ARKANSAS’S 2018 INTEGRATED RESOURCE PLAN

The stakeholders that participated in the Entergy Arkansas Inc. (“EAI”) Integrated

Resource Plan (“IRP”) thank the company for providing information and assisting the

stakeholders in understanding EAI’s policy and planning objectives of the IRP for the next 20

years. The stakeholders agreed at the start of the IRP process to avoid suppressing contrary

opinions and comments. For the purpose of concluding its review of the 2018 IRP, the

stakeholders recommend to EAI that it should consider and respond to each issue and

recommendation as presented in the comments.

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TABLE OF CONTENTS

STAKEHOLDER COMMENTS REGARDING ENTERGY ARKANSAS’S 2018 INTEGRATED RESOURCE PLAN .............................................................................................. 1

I. Comment Topic: Stakeholder Process ................................................................................. 3

Simon Mahan, Southern Renewable Energy Association

II. Comment Topic: Modeling Deficiencies ............................................................................ 8


III. Comment Topic: Transmission Assumptions ............................................................... 17


IV. Comment Topic: Renewable Energy Assumptions ...................................................... 19


V. Comment Topic: DSM and Demand Response Assumptions .......................................... 27

Peter Dotson-Westphalen, CPower Energy Management for Advanced Energy Management Alliance

VI. Comment Topic: Energy Storage Assumptions ............................................................ 31


VII. Comment Topic: Coal .................................................................................................... 35

Jordan Tinsley, Arkansas Electric Energy Consumers, Inc.

VIII. Comment Topic: Energy Efficiency .............................................................................. 40

Gary Moody, National Audubon Society

IX. Comment Topic: Coal .................................................................................................... 42

Tony Mendoza, Sierra Club

X. Comment Topic: Advanced Nuclear ................................................................................. 47

Katie Niebaum, Arkansas Advanced Energy Association

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I. Comment Topic: Stakeholder Process


Other Stakeholders Joining This Comment: Advanced Energy Management Alliance, Arkansas Electric Energy Consumers, Inc., and Sierra Club.

* * *

Arkansas’ Integrated Resource Planning (IRP) Guidelines provide a few explicit

requirements for utility resource planning.1 EAI has followed some of the Commission’s

Guidelines, while others have been left deficient, and others entirely ignored.

A. Evaluation of EAI IRP Process

The Arkansas IRP process is unique compared to processes across the southeast. For

instance, individual utilities do not appear to have standard service lists, there are rarely publicly

posted information about the IRP processes or timelines, and it is difficult for stakeholders to get

engaged in the various IRPs without first initially contacting the utilities ahead of the initial

stakeholder meeting. Stakeholders that are unable to make the first (and frequently, only) in-

person meeting often have little ability to provide input and interact with Stakeholder

Committees after the first meeting. Requests made of the utility at the stakeholder meeting may

or may not be documented, and may or may not be responded to. For example, a number of

questions at the EAI stakeholder meeting held on June 6, 2018 were not answered and EAI did

not provide estimated timelines for when questions would be responded to.

While the Stakeholder Committee is empowered to create its own rules and procedures,

those rules and procedures are commonly left unstated and informal due to insufficient time.

Stakeholder Committees frequently lack a “point person” to pull together the Committee’s

1 http://www.apscservices.info/Rules/resource_plan_guid_for_elec_06-028-R_1-7-07.pdf

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requests of a utility, and development of Committee milestones or goals also frequently do not

occur.

The current Stakeholder Committee on this EAI IRP requested the company not rely on

capacity-only resource planning, that renewable energy prices be lowered to reflect current

market realities, and that certain power plant retirements be accelerated in various sensitivity

scenarios. None of those requests were fulfilled, and it was only until mid-October when EAI

provided its final set of IRP information that the Stakeholder Committee realized that the

company would not be fulfilling any of these requests.

When compared to the SWEPCO Arkansas IRP process, this EAI process underscores

significant deficiencies in this current EAI process, and the Arkansas IRP Guidelines broadly.

• EAI did provide slides ahead of the June 2018 stakeholder meeting; however, the company did not provide preliminary results prior to the meeting. As such, stakeholders learned of some of the modeling problems at the meeting itself and had to interpret the results in real time.

• EAI did provide a number of responses to those questions in four sets of “Follow Up” material and one “Modeling Update”; however, Stakeholders were not provided with a timeline for when information would be provided, and even if all requests would be responded to.

• A number of requests were not addressed by EAI. For example, stakeholders requested current unit heat rates and operational costs. EAI responded regarding that information in its second Follow Up, and stated the information “constitute market sensitive data.”2 However, Stakeholders were able to find such information, publicly available and provided by Entergy to its annually published Investors Guide.3 Similarly, renewable energy capital cost assumptions were also deemed market sensitive and kept confidential.

B. SWEPCO Comparison

Several Stakeholders have also been involved with the SWEPCO IRP process in

Arkansas. The SWEPCO IRP process is truly a cooperative effort between the utility and the

2 http://entergy-arkansas.com/content/IRP/2018/Follow-Up_Materials_Set_2.pdf 3 http://www.entergy.com/content/investor_relations/docs/2017_Investor_Guide.pdf

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Stakeholder Committee; whereas the EAI IRP process has been marked with lackluster utility

engagement, poor information exchange, and insufficient research. SWEPCO IRP Stakeholders

have been allowed to provide two sets of questions, along with a list of model sensitivity run

improvements – virtually all of which have been responded to by SWEPCO, by a clear deadline

set by SWEPCO. SWEPCO staff have earnestly engaged in dialog, and even provided

stakeholders a webinar to present information and allow an additional opportunity for

engagement. Because SWEPCO has conducted a robust and collaborative stakeholder process,

that stakeholder report is likely to be highly supportive of SWEPCO’s findings and minor in

content. The fact that Stakeholders can have such drastically different experiences between the

EAI and SWEPCO IRPs suggests that the IRP rules themselves are deficient in providing a

standard quality of engagement, and that Stakeholders are almost entirely dependent on utility

staff being earnest, interested and eager to cooperate.

C. IRP Guidelines Ignored

While the Arkansas IRP Resource Guidelines are not prescriptive, they do suggest

several deficiencies:

• APSC Guidelines Section 3 states, “Resource planning will be relevant to future resource investment decisions and approval proceedings, as well as revenue requirements and rate design.” However, in several occasions at the Stakeholder Meeting, EAI staff seemed to indicate that the IRP would mostly be ignored and is not considered a driving-force for future decisions.

• It does not appear that EAI formally established the Resource Plan objectives. Per the APSC Guidelines, Section 4.1, “The utility shall clearly state and support its objectives. The objectives of the Resource Plan include, but are not limited to, low cost, adequate and reliable energy services; economic efficiency; financial integrity of the utility; comparable consideration of demand and supply resources; mitigation of risks, consideration of environmental impacts; and consistency with governmental regulations and policies.”

• Per APSC Guidelines Section 4.3 “The utility should assess existing resources based on their cost effectiveness and considering the utility’s planning objectives.” However,

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Stakeholders are unable to help provide assessment of existing resources based on their cost effectiveness without relevant information, such as heat rates and operational costs.

• EAI has not provided economic comparisons between the various futures, as required by APSC Guidelines Section 4.4, which states that, “The portfolios should be compared on the present value of the cost of each.”

• Stakeholder comments specifically requested EAI evaluate power purchase agreement (PPA) options, as well as purchases in the MISO Market. Indeed, those items are required by APSC Guidelines Section 4.6 “A self-build option must be compared to market opportunities.” Yet, such comparisons have not been made.

D. Stakeholder Questions and Requests Ignored

Per the APSC’s Resource Planning Guidelines, “The reason for stakeholder involvement

is to open up the planning process and provide an opportunity for others with an interest in the

planning process to provide input as a check on the reasoning of a utility during the development

of the resource plan.” However, if stakeholder questions and observations are ignored,

unanswered, or unresolved, stakeholder involvement in the IRP process has failed to serve as “a

check”. There is no recourse for stakeholders to resolve unresolved issues. Here is a synopsis of

some questions and requests asked of EAI that went unresolved:

• Wind/solar prices should continue to decline over time. • The PTC/ITC for wind and solar is not accurately reflected. • EAI should model PPA versions for wind/solar. • Provide megawatt values for various scenarios regarding the MISO market futures. • Provide planned unit deactivated in the MISO market based on the 60, 55 and 50 year

lifetimes. • How are variables tied together – in a low economy, it’s possible the economy is low due

to high fuel prices, but there seems to be no connection between any of those variables in the narrative.

• Provide MW values of market coal/gas deactivations, and MW values of incremental market resources, including on a unit-level.

• EAI should incorporate MISO capacity purchases as a resource option. • EAI should evaluate an expanded MISO North/South connection as a resource option.

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E. EAI Devalued the IRP Process

Stakeholders raised significant concern over EAI’s capacity-only planning methodology.

EAI staff explained that the modeling software would only evaluate capacity solutions, meaning,

until pre-determined capacity needs were inserted into the modeling parameters, no new

generation resources would be procured. In fact, that explanation was borne out in all three

futures in the preliminary results presented on June 6, 2018, whereby no new generation was

added until 2025, when the Lake Catherine Unit 4 was pre-determined to retire in the model.

Concern was raised at the stakeholder meeting by several stakeholders that capacity-only

planning would eliminate low-cost energy solutions that may reduce overall operational costs,

and costs to ratepayers. As a model alternative, stakeholders recommended using the Plexos suite

of software tools as opposed to the AURORA modeling software. SWEPCO already uses Plexos,

as does MISO, in resource planning. EAI staff strongly suggested that business decisions made

by EAI are not bound by the IRP, and thus the IRP outcomes are not the only resource planning

results; however, these statements which were meant as reassurances, were suggestive that EAI

would simply ignore the IRP results, further weakening the value of the IRP process as well as

stakeholder involvement.

Stakeholders also encouraged EAI to evaluate MISO capacity and energy purchases as

opposed to only evaluating self-build options. EAI responded that the MISO capacity and energy

markets were too short-term, and that the company would only look at long-term solutions.

However, when Stakeholders suggested that Demand Response opportunities should be properly

valued, EAI staff cited low-cost MISO capacity prices as a justification to devalue those

resources. EAI staff rather flippantly also stated that the company planned to eliminate the DR

program altogether because MISO capacity prices were so low.

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Conclusion

Given the extensiveness of these comments along with the additional Stakeholder

Committee report, the Stakeholder Committee believes that EAI has failed APSC Guidelines

Section 4.8, that “[t]he utility shall make a good faith effort to properly inform and respond to

the Stakeholder Committee.” The APSC Guidelines provide little recourse for a deficient IRP

process, only stating that Section 4.8 “If comments concerning the process and results warrant,

the Commission may require the utility to re-evaluate and resubmit its Resource Plan for the

current planning cycle to address concerns raised in the comments.” The Stakeholder Committee

encourages the APSC to exercise its option in requiring an updated IRP by EAI. The Stakeholder

Committee also recommends to the APSC to open a new docket to reform the IRP rules in an

effort to fix the deficiencies experienced in this IRP process.

II. Comment Topic: Modeling Deficiencies


Other Stakeholders Joining This Comment: Advanced Energy Management Alliance, Arkansas Electric Energy Consumers, Inc. (only the section regarding MISO capacity market purchases), and Sierra Club

* * *

Entergy has developed multiple IRPs in 2018, including for Entergy Arkansas (EAI),

Entergy Louisiana (ELL) and Entergy Mississippi (EMI), as well as ongoing work in the Entergy

New Orleans (ENO) market. While the focus of these comments is on EAI and the IRP process

in Arkansas, there are lessons to be learned from the other Entergy subsidiaries and processes. In

some instances, data sets have been provided in one proceeding while blocked in others (such as

renewable energy cost assumptions), methodologies have been written in narrative form or at

least documented, and comparisons may provide information to fill knowledge gaps. Overall, it

appears Entergy performs a fairly consistent IRP process across its entire footprint, making a

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comparative analysis not only more informative, but more accurate in identifying potential

deficiencies in processes. The current process suffers from several modeling deficiencies,

including:

• Does not optimize for low-cost energy procurement • Does not result in retirement recommendations • Does not model sub-hourly generation and load • Does not incorporate MISO capacity purchases as a power resource option • Does not use MISO-developed futures

A. AURORA Modeling Deficiencies

Entergy Arkansas (EAI) relies heavily on the “capacity planning” software called

AURORA. Regarding modeling software and capabilities, EAI should develop a study detailing

the various benefits and limitations of its current modeling software. In 2017, Puget Sound

Energy (an electric utility in Washington state), conducted a brief overview of AURORA versus

Plexos software, highlighting the benefits of using the Plexos software. AURORA is a capacity-

centric modeling product, whereas Plexos appears to have greater flexibility in evaluating lowest

cost energy resources, capacity resources and sub-hourly ancillary services. Capacity-centric

planning tends to focus on generator-based solutions (retirements, new construction or general

ramping capabilities). Based on analysis by Puget Sound Energy, the AURORA suite of products

focuses on hourly capacity-based operations; however, Plexos can provide sub-hourly

operational capabilities. Such modeling software flexibility is exceptionally important for

variable energy resources (such as wind energy and solar energy) which have sub-hourly

ramping capabilities, and energy storage systems, which can provide ancillary services on a sub-

hourly basis. Currently, Plexos appears to be better software compared to AURORA. For

comparison, both MISO and SWEPCO uses Plexos software.

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At the EAI stakeholder meeting in June 2018, the IRP team noted that there are

significant deficiencies in the IRP modeling software program itself and its negative implications

for renewable energy resources. EAI stated, “Reference Case Future: the proportion of

renewables as part of the future portfolio is smaller than in the 2015 IRP Capacity Expansion

Modeling (Future 1) even though the technology cost assumptions are lower. Several factors

are contributing to this result, but the biggest impact is coming from recently added AURORA

dynamic modeling enhancements…Based on the initial evaluation of results from the 2018 IRP

modeling, it appears that AURORA is seeing the capacity shortage in the afternoon/evening as

demonstrated in the example on the previous slides. The model seems to be addressing this

shortage by building gas technologies rather than renewables, even if its first preference is

renewables.”4 (emphasis added).

When deficiencies regarding the AURORA model have been presented by stakeholders,

Entergy’s common response has been that the utility has relied on AURORA for a number of

IRPs and finds no need to change. ELL has stated, “ELL adopted AURORA for long-term

energy price forecasting and production costing in 2013 and has used AURORA for several

resource certifications and IRPs that were accepted by the LPSC. ELL regularly reviews the

software alternatives available to meet its long-term energy price forecasting and production

costing needs and currently it has determined that AURORA best meets those needs.”5 Since

Entergy adopted the use of AURORA in 2013, MISO South has been developed.

4 http://entergy-arkansas.com/content/IRP/2018/June_6_Stakeholder_Meeting_Materials.pdf 5 http://www.entergy-louisiana.com/content/irp/2019/ELL_IRP_2019.pdf

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B. Current Capacity Planning Does Not Identify Opportunities for Deactivation or Retirement

In keeping with capacity planning, without a formal input of a capacity need, a model

will not return a result showing new capacity being built. Such inputs are frequently planned

retirements or deactivations. Entergy appears to conduct retirement and deactivation studies

outside of the IRP context. The Entergy IRPs rely on these previously determined retirement

schedules and dates as inputs to the IRP models, and it does not appear that the IRPs have any

bearing on identifying units for possible retirement or deactivation.

• EAI has stated, "The market price of energy is one of several factors that may influence a particular deactivation opportunity. Such an evaluation is part of a separate planning process, and the result of that process is an input to the IRP model."6

• ELL has been requested by the Louisiana PSC to effectively provide these analyses, and ELL has stated, "As a part of its robust and iterative long‐term planning processes, the Company continually monitors and studies the condition of units, market conditions, and economics to evaluate whether legacy units are candidates for deactivation or retirement. Consistent with the LPSC directive from the February 21, 2018 open session, ELL will conduct a comprehensive evaluation to assess the continued operations and role of its legacy fleet."7

• EMI has stated, “Recently, a cross-functional evaluation team conducted assessments and analyses of the units at the Baxter Wilson facility, which consisted of a comparison over a particular time frame of the cost of continuing to maintain and reliably operate the specific units to the cost of deactivating the units and obtaining newer, reliable replacement capacity over that same time frame. … The result of that effort found that it was reasonable to adjust the Baxter Wilson unit 2 deactivation date to 2018 and to adjust the Baxter Wilson unit 1 deactivation planning assumption to an earlier-than-previously-assumed deactivation date. …In addition to the analysis of Baxter Wilson unit 2, EMI also reviewed the economics associated with required improvements to continue to operate Rex Brown 3 in a safe and reliable manner. That review concluded the costs associated with continued operation of Rex Brown 3 in addition to the near-term assumed deactivation date of 2019 for the unit, made further investment uneconomic. Based on the results of the review, EMI retired Rex Brown 3 in 2018.”

Retirements and deactivations are therefore “baked in” assumptions for IRP planning

purposes across the Entergy footprint. Capacity-centric planning, as performed by Entergy in its 6 http://entergy-arkansas.com/content/IRP/2018/Follow-Up_Materials_Set_2.pdf 7 http://www.entergy-louisiana.com/content/irp/2019/ELL_IRP_2019.pdf

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IRPs, is not optimizing energy purchases nor identifying existing generation for possible

retirement.

C. Capacity Planning Ignores Low-Cost Energy Resources

The preliminary results provided to stakeholders at the June 2018 meeting suggested that

EAI would add no new capacity until approximately 2025, when the utility plans to retire Lake

Catherine Unit 4. For comparison, ELL’s capacity position shows a capacity need in roughly

2027. After the addition of a new CCGT in 2023, EMI’s capacity position does not show a

capacity need until the year 2030. When asked directly, “Will the AURORA model select a low

cost energy resource if no capacity need exists?” EAI responded, “No; AURORA only

selects/builds resources based on capacity need.”8 Stakeholders have asked as a hypothetical, if a

$0/MWh energy resource were readily available would AURORA select the resource? Entergy

staff have stated in several fora that the AURORA model would not select those resources

without a capacity need. As a follow-up, some Entergy staff have stated that despite this

deficiency in the AURORA model, that Entergy would ignore the results of the IRP to procure

low-cost energy resources, if such resources were made available. As such, Entergy’s current

capacity-only planning methodology is ignoring potentially lower cost energy resources, such as

renewable energy resources, that may reduce overall system costs.

In fact, the renewable energy capacity additions provided in Entergy’s IRPs do not match

with Entergy’s own investor analysts’ presentations and announcements. Based on IRPs from

Entergy Arkansas (EAI), Entergy Louisiana (ELL) and Entergy Mississippi (EMI), and Entergy

New Orleans (ENO), Entergy plans to add roughly 200-300 MW of solar power by 2025. Rod

West, Entergy's Group President of Utility Operations, stated on June 21, 2018 that Entergy's

8 http://entergy-arkansas.com/content/IRP/2018/Follow-Up_Materials_Set_3.pdf

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five-year plan includes renewable energy with “~1,000 MW in various stages of development”.9

While this summary of IRPs does not include Entergy Texas (ETI), it seems infeasible that the

remaining quantity of announced renewable energy would be covered solely in Texas.

Effectively, due to IRP planning deficiencies, Entergy plans to ignore its IRPs.

D. MISO Capacity Market is Ignored

In all three IRPs, Entergy ignores the MISO capacity market as a potential resource.

Entergy claims that the MISO capacity market is too short-term to be of any value for evaluation.

For example, Louisiana Public Service Commission staff requested that ELL “include

information detailing how excess capacity available through MISO and potential purchase power

agreements were considered as available alternative resources in the Company's analysis.” ELL's

response was that, “Excess capacity available through MISO is not guaranteed long-term and

partially a function of proactive planning actions of regulated utilities such as ELL. Accordingly,

excess market capacity is not considered as an option for meeting long-term planning objectives

such as the reserve margin. Resource alternative inputs to the model are developed from a

financial perspective assuming utility ownership.” EMI similarly states, “the MISO Resource

Adequacy process establishes minimum requirements that must be met in the short term and are

reviewed regularly as part of the resource planning process, it does not provide an appropriate

basis for determining EMI’s long-term resource needs.” EAI similarly does not evaluate MISO

capacity purchases.

While Entergy excludes MISO capacity as a potential resource in its modeling, Entergy

simultaneously uses low-cost MISO capacity as a justification to de-value Demand Response

(DR) programs. At the EAI meeting in June 2018, Entergy staff flippantly mentioned the utility

9 Entergy (June 21, 2018). Utility, Reimagined. Analyst Day. [https://entergycorporation.gcs-web.com/static-files/5adf1e57-d0f1-469f-bac8-ca188b0f4d2e]

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was planning on eliminating DR programs. EAI stated that, “… the continued low capacity

prices in MISO South are negatively impacting the cost-effectiveness of the DR programs.”10

Entergy’s contradictory positions on evaluating MISO’s capacity likely lead to model

runs that incorporate more costly new generation resources, while ignoring lower cost capacity

purchases and DR programs.


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E. Futures Development

EAI, ELL and EMI use a mixture of futures development that are all nearly the same, but

without clear explanation regarding interrelations. For example, in the “Reference” Futures 1, all

three assume market deactivations of coal and legacy gas units after 60 years of operation, which

results in 12% of the MISO market being converted to 33% renewable energy and 64% natural

gas by 2028; all use a “reference” CO2 price; and, all use a reference natural gas price of around

$5/mmbtu. In the Futures 2 scenarios, EAI, ELL and EMI all use roughly the same metrics;

however, EAI assumes low load growth, while ELL and EMI assume high load growth. EAI also

assumes a price on carbon dioxide emissions whereas ELL and EMI do not. EAI’s Future 3

Load Growth Coal/Gas Age Deactivations

MISO Market Conversion

Conversion Mix CO2 Price

Gas Price

Future 1 EAI Ref. 60 years 12%x2028 34% RE/66% Gas

Ref. $5.01

Future 1 Future 2

ELL Ref. 60 years 12%x2028 34% RE/66% Gas

Ref. $4.81

EMI Ref. Ref. N/A 34% RE/66% Gas

Ref. Ref.

EAI Low 55 years 31%x2028 25% RE/75% Gas

Low $3.40

Future 2 Future 3

ELL High 55 years 31%x2028 25% RE/75% Gas

None $3.27

EMI High “Moderate” N/A 25% RE/75% Gas

None Low

EAI High 50 years 54%x2028 50% RE/50% Gas

High $6.78

Future 3 Future 4

ELL Low 50 years 54%x2028 50% RE/50% Gas

High $3.27

EMI Low “Accelerated” N/A 50% RE/50% Gas

High Low

EAI Future 4 ELL High 55 years 31%x2028 50% RE/50%

Gas Ref. $6.70

EMI High “Moderate” N/A 50% RE/50% Gas

Ref. High

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aligns more closely with ELL’s and EMI’s Future 4, due to high load growth, high CO2 pricing

and high gas prices. It is unclear how, for instance, high gas prices affect individual utility load

growth. Presumably higher natural gas prices would likely lead to lower load growth, or that

high CO2 prices would lead to significantly more renewable energy development. Stakeholders

involved in the EAI process requested a narrative explaining how resources interrelate, however

no clear narrative has been provided explaining how seemingly mutually exclusive future

assumptions exist together.

In both EAI and ELL IRP stakeholder processes, it has been requested by stakeholders

that Entergy should rely on MISO’s Futures developed through the MISO Transmission

Expansion Planning (MTEP) process. MISO’s TEP process is annually updated, and Energy has

been heavily involved in all steps regarding the MTEP process, including futures development.

Even if Entergy chooses to not adopt the MISO Futures for its own IRP planning, Entergy should

develop some sort of comparison between MISO’s Futures and its own Futures, to highlight

areas of similarity and difference.

One note of importance, it appears that MISO’s Futures have a more holistic look at the

footprint, in terms of what generators are likely to be retired over the time horizon evaluated.

MISO collects information from all of its members regarding actual retirement dates, and uses

other methodologies to determine possible retirement dates for units where a retirement date is

not yet planned or is unknown. Entergy uses a 60-year, 55-year and 50-year age methodology for

retirement assumptions. ELL has noted that, “an Electric Power Research Institute (EPRI)

analysis performed in 2012 projected that the average age of natural gas steam turbine

retirements as of 2016 would be 52.9 years old. A 2017 study performed by the Lawrence

Berkley National Laboratory (and supported by the Department of Energy) produced similar

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results finding that the most common age of recently retired natural gas steam turbines was

between 40 and 50 years. This is consistent with the 52.4 years average life of the Entergy

Operating Companies’ natural gas steam turbines either deactivated or retired since 2000. Given

these trends, there is risk that ELL’s legacy gas units may not be economic or feasible to operate

through their assumed 60 year useful life.” As such, using 60-years as Entergy’s “reference” case

for existing legacy generation units in MISO, or even for itself, may be overly optimistic. It

appears MISO has already corrected for this in its Futures.11

Recommendations

• EAI should provide a comparative analysis regarding various modeling programs (e.g., AURORA vs. Plexos).

• EAI should conduct long-term planning beyond solely capacity planning. Ideally, EAI would rely on energy-planning, too.

• EAI’s IRP should be capable of identifying potential retirement opportunities and those recommendations should be made in this IRP.

• EAI should use MISO’s Futures, or at least provide some sort of comparison of similarities and differences.

• EAI should incorporate the possibility of MISO capacity purchases and/or MISO energy purchases.

• EAI should provide futures/portfolio cost estimates, similar to what is done with EMI.

III. Comment Topic: Transmission Assumptions


Other Stakeholders Joining This Comment: Arkansas Electric Energy Consumers, Inc. and Sierra Club

* * *

EAI did not evaluate expanding transmission options in this IRP. With regards to

transmission evaluations, it is well known that the MISO North/South interconnection is a severe

limitation for power flow between the two regions. By pre-determining the MISO system

constraints continue to exist in perpetuity, EAI has ignored a potentially lower-cost alternative to 11 http://www.entergy-louisiana.com/content/irp/2019/ELL_IRP_2019.pdf

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building new generation – namely, building new high capacity transmission to lower-cost

resources in MISO North or to SPP. EAI stated, “For the IRP capacity expansion modeling, the

import and export limits between MISO regions is an input assumption and is not varied to

accommodate future resource additions. The resource additions are based on generic assumptions

for EAI-sited resources but do not represent or imply a selection of any specific resource or

location. Outside of the scope of the IRP, any evaluation of potential resources located in SPP

would be resource-specific and handled individually. Such an evaluation would require inclusion

of all the costs required to deliver the energy to MISO South.”12

During the January and September 2018 Maximum Generation Events, higher levels of

North/South flow would have better served MISO South than calling on emergency power

purchases from outside the MISO footprint. Several meetings held by both MISO and SPP

suggest that when emergency prices were set in both the January and September events, that

those exceptionally high emergency prices for imported power would be “uplifted” to the entire

MISO footprint. Stated another way, MISO North is likely to subsidize MISO South’s Maximum

Generation Events. Given that two Maximum Generation events occurred in the same year

during historically non-peak periods, the likelihood of further Maximum Generation Events

appears to be exceptionally high, with no clear plan to resolve these issues in the future.

Currently, there appears to be few venues for MISO to evaluate transmission expansion based on

these extreme events; thus, absent such analysis from MISO, MISO South utilities should

conduct some minor levels of evaluating expanding transmission connections between the North

and South.


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Modeling higher levels of interconnectivity between MISO North/South and SPP should

not be difficult. For instance, EAI could have developed cost metrics for installing a new

transmission line, and possible cost allocation scenarios, coupled with average hourly LMP from

MISO North or SPP, or perhaps a flat-cost wind power purchase agreement. These metrics, when

added together, would appear much like a new power station in MISO South. As such,

transmission resources could serve the same or similar purposes as new-build power generation,

and should have been evaluated.

Recommendation

• EAI should develop a transmission expansion plan, in addition to what MISO and SPP perform.

• EAI should evaluate the effect of potentially expanding the MISO North/South interconnection. Such an evaluation could look at an expansion of 1 GW, 5 GW, 10GW and 20 GW to create a broad set of sensitivities.

IV. Comment Topic: Renewable Energy Assumptions


Other Stakeholders Joining This Comment: National Audubon Society and Sierra Club

* * *

A. Renewable Energy Data Assumptions

The National Renewable Energy Lab (NREL) publishes its Annual Technology Baseline

(ATB) as a resource for “realistic and timely set of input assumptions (e.g., technology cost, fuel

costs), and a diverse set of potential futures (standard scenarios) to inform electric sector analysis

in the United States. The products of this work, including assessments of current and projected

technology cost and performance for both renewable and conventional electricity generation

technologies, as well as market projections of more than a dozen scenarios produced with

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NREL's Regional Energy Deployment Systems (ReEDS) model….”13 NREL’s ATB is one of the

most comprehensive, and accurate, resources for various energy resource inputs. NREL’s ATB is

used by regional transmission organizations (RTOs) including the Midcontinent Independent

System Operator (MISO)14 and PJM.15 NREL’s ATB data should be used for model inputs and

future forecasts. Given that future purchases of renewable energy resources would take several

years before power production, NREL ATB data starting in 2019 or 2020 is recommended, as

well as incorporating future pricing and performance levels. NREL’s ATB is updated annually,

usually in July or August.

1. Wind Energy

NREL’s ATB evaluates wind energy resources as “techno-resource groups” (TRGs) that

effectively provides a scale of various wind energy opportunities.16 For example, TRG 1

resources are anticipated to be the lowest cost and highest performance wind energy resources,

and are mostly concentrated in the Central US. A fair amount of wind energy capacity potential

in the Southeast opens in TRG 5, with the entire Southeastern region opening up with TRG 7.

Based on the current market, the “low” values for NREL ATB’s land-based wind resources

should be used, beginning in 2019 or 2020. Evaluating these three different wind energy

resources provides an adequate range of wind energy resources available to the Southeast. 13 NREL (National Renewable Energy Laboratory). 2018. 2018 Annual Technology Baseline. Golden, CO: National Renewable Energy Laboratory. http://www.nrel.gov/analysis/data_tech_baseline.html. 14 Midcontinent Independent System Operator (March 20, 2018). "MTEP19 Futures Development Workshop." [https://cdn.misoenergy.org/20180320%20MTEP19%20Futures%20Workshop%20Presentation150635.pdf] 15 Muhsin K. Abdur-Rahman (April 25, 2016). "PJM's Clean Power Plan Modeling Reference Model and Sensitivities," PJM. [https://www.pjm.com/-/media/committees-groups/committees/mc/20160425-webinar/20160425-item-02-clean-power-plan-reference-model-results.ashx] 16 National Renewable Energy Lab (November 2016). Regional Energy Deployment System (ReEDS) Model Documentation: Version 2016. [https://www.nrel.gov/docs/fy17osti/67067.pdf]

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Evaluating multiple types of wind energy resources, and not solely evaluating the lowest

cost options (e.g., TRG 1 resources), may help identify different generation profiles that more

closely align with a particular utility’s demand load. Geographic diversity of renewable energy

resources is anticipated to generally increase capacity value of a particular resource and reduce

overall generation variability. Hourly and sub-hourly wind energy generation profiles are

available from the NREL Wind Integration National Database (WIND) Toolkit for up to 122,000

different sites across the country. Data are available from NREL, here:

https://www.nrel.gov/grid/wind-toolkit.html

The federal Production Tax Credit (PTC) for wind energy is expiring. The details of the

PTC will be discussed later; however, for the chart below, the PTC has been converted into a

rough reduction in overnight capital costs. Generally, CAPEX costs below have been reduced by

$600/kW in 2019 and 2020, $500/kW in 2021, and $400/kW in 2022.

NREL ATB Wind Energy Pricing Examples With Production Tax Credit as Overnight

Cost Reduction ($/kW) by Year

2019 2020 2021 2022 2023* 2024* 2025* TRG1 Overnight $/kW $730 $687 $739 $787 $1,133 $1,075 $730

Capacity Factor 50% 50% 51% 51% 52% 52% 53% LCOE $/MWh $19 $21 $22 $23 $27 $26 $24

TRG5 Overnight $/kW $840 $803 $839 $874 $1,208 $1,142 $1,075 Capacity Factor 44% 45% 45% 46% 47% 48% 48% LCOE $/MWh $25 $26 $27 $28 $31 $29 $28

TRG7 Overnight $/kW $1,013 $991 $1,023 $1,054 $1,384 $1,313 $1,241 Capacity Factor 35% 36% 37% 38% 38% 39% 40% LCOE $/MWh $39 $40 $39 $39 $41 $39 $36

Source: based on LBNL 2014, 2018 NREL ATB *No PTC Value

2. Solar Energy

Costs for fixed-tilt versus single-axis tracking solar projects are estimated to be

approximately similar, with minor capital cost and maintenance cost differences; however,

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capacity factors are anticipated to increase significantly with single-axis trackers. NREL’s ATB

only evaluates single-axis tracking systems, with the best performing projects achieving an

estimated 27% capacity factor (NREL ATB projects located in Daggett, CA). As a proxy for

fixed-tilt solar projects, it is recommended that a 20% capacity factor be used (NREL ATB

projects located in Kansas City, MO). NREL’s ATB converts solar DC power to AC power

output for capacity factor purposes, while keeping several financial metrics in $/kWDC units.

To provide a better range of pricing and performance, it is recommended that the “Mid”

overnight costs for Kansas City and Daggett utility-scale solar projects from NREL’s ATB

should be used, along with the 20% and 27% capacity factors, respectively, beginning in 2019.

Due to new guidance from the IRS, solar power projects that qualify for the 30% ITC in

2019, 26% ITC in 2020, or the 22% ITC in 2021 each have until the end of the year 2023 to

become operational. A 10% ITC is available for projects that commence construction in or after

2022, and for projects that become operational in or after 2024. At the same time the federal ITC

is slated to decline, the NREL ATB shows that solar power installed costs are anticipated to

decline, almost in the exact same proportion as the ITC phase-out through 2023. Applying the

ITC phase-out to the NREL ATB 2018 overnight capital costs, results in overnight costs of

approximately $700/kWDC for projects that begin construction between now and 2021, which

are also operational by the end of 2023. By 2024, when the bulk of the ITC has expired, solar

pricing is anticipated to decline an equivalent amount, thus overall levelized cost of energy of

utility-scale solar projects are anticipated to remain relatively flat from 2019-2030. For utility-

scale solar projects with 20% capacity factors, and taking the ITC into account for near-term

projects, overall LCOE is anticipated to remain in the mid-$30s/MWh range for the next decade.

For projects with 27% capacity factors, LCOE values in the $20s/MWh are anticipated. We have

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worked with utility-scale solar development companies in the region who have corroborated the

view that utility-scale projects in BREC region can be currently be delivered with an LCOE in

the mid-$30/MWh range thanks to the ITC value and for the decade ahead with the forecasted

future cost-declines following the ITC step-down to 10%.

NREL ATB Utility-Scale Solar Energy Pricing (ITC Included)

2019 2020 2021 2022 2023 2024 2025 Mid Overnight $/kWdc $707 $707 $707 $707 $707 $784 $775

Capacity Factor AC 20% 20% 20% 20% 20% 20% 20% LCOE $/MWhAC $32 $32 $32 $$32 $32 $38 $38

Low Overnight $/kWdc $707 $707 $707 $707 $707 $784 $775 Capacity Factor AC 27% 27% 27% 27% 27% 27% 27% LCOE $/MWhAC $20 $20 $20 $20 $20 $24 $23

Source: NREL ATB 201817, 20-year LCOE, “Mid” is Kansas City, “Low” is Daggett

B. Market-Based Benchmarking

Many utilities have issued requests for proposals (RFPs) for renewable energy resources

from around the country; however, not all utilities publicly summarize results from those

solicitations. Wherever recent results from renewable RFP solicitations are made public, it is

highly encouraged that those data be used as benchmarks when developing IRP data inputs.

It is highly recommended that utilities should develop a request for proposals (RFP) or

request for information (RFI) in tandem with IRP development to receive the most recent market

information, specific to that utility. Developing an RFP or RFI to coincide with an IRP would

create a significant amount of high quality data, while potentially expediting future power

purchase agreements, procurements or developments.

1. Xcel Energy Colorado All-Source Solicitation

17 National Renewable Energy Lab (July 2018). NREL Annual Technology Baseline (ATB) 2018. [https://atb.nrel.gov/]

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Xcel Energy, a Colorado electric utility, published the results of its 2017 All-Source

Solicitation request for proposals in December 2017.18 Xcel received over 400 bids representing

over 100,000 MW of capacity from a wide variety of technologies; however, most bids provided

wind energy or solar power resources. The median bid price or equivalent for stand-alone wind

energy resources was $18.10/MWh, suggesting several projects below and above that price.

Adding battery storage to wind energy resulted in median bids of $21/MWh. For stand-alone

solar energy resources, the median bid was $29.50/MWh. Adding battery storage to solar energy

resulted in median prices of $36/MWh. While these prices may be specific to Xcel, the fact

remains that these represent real project bids and are aligned with projections by NREL’s ATB,

Lazard Associates and these comments.

18 Xcel Energy (December 28, 2017). 2016 Electric Resource Plan, 2017 All Source Solicitation 30-Day Report (Public Version) CPUC Proceeding No. 16A-0396E. [https://assets.documentcloud.org/documents/4340162/Xcel-Solicitation-Report.pdf]

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Xcel RFP Responses by Technology 2017

Source: Xcel Energy 201719

2. Northern Indiana Public Service Company Request for Proposals

Northern Indiana Public Service Company (NIPSCO), an electric company in the MISO

system, held an integrated resource plan (IRP) meeting on July 24, 2018 to discuss renewable

energy options. As part of its IRP process, NIPSCO shared results from an all source request for

proposals (RFP) summary. NIPSCO received bids for wind energy, solar energy, energy storage,

and amalgamations of those resources together. The company received proposals across five

states, predominately via power purchase agreement (PPA), but also as asset sale or option.

Resources offered as asset sale or as an option were provided at an average bid cost of

$1,151.01/kW for solar energy projects, and $1,457.07/kW for wind energy projects. For PPA’s,

average bids for solar energy reached $35.67/MWh, and average bids for wind energy reached

$26.97/MWh. Solar plus energy storage projects were offered as asset sales at $1,182.79/kW and

19 Xcel Energy (December 28, 2017). 2016 Electric Resource Plan, 2017 All Source Solicitation 30-Day Report (Public Version) CPUC Proceeding No. 16A-0396E. [https://assets.documentcloud.org/documents/4340162/Xcel-Solicitation-Report.pdf]

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also as a PPA at $5.90/kW-Mo plus $35/MWh.20 These values provide recent market data that

are relevant to states in MISO and further south.

NIPSCO RFP Responses by Technology 2018

Source: NIPSCO 2018.21

Recommendations

• EAI should model multiple types of wind energy resource, including resources from SPP, MISO and inside Arkansas.

• EAI should model both fixed and tracking solar energy resources. • EAI should use NREL’s ATB regarding energy pricing, performance levels and

forecasts. • EAI should incorporate the federal Production Tax Credit and Investment Tax Credit. • EAI should benchmark its data assumptions against publicly available information. • EAI should immediately issue an RFP for renewable energy resources.

20 Northern Indiana Public Service Company (July 24, 2018). NIPSCO Integrated Resource Plan 2018 Update Public Advisory Meeting Three. [https://www.nipsco.com/docs/default-source/about-nipsco-docs/7-24-2018-nipsco-irp-public-advisory-presentation.pdf] 21 Northern Indiana Public Service Company (July 24, 2018). NIPSCO Integrated Resource Plan 2018 Update Public Advisory Meeting Three. [https://www.nipsco.com/docs/default-source/about-nipsco-docs/7-24-2018-nipsco-irp-public-advisory-presentation.pdf]

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o This RFP should be completed in a single year. The current RFP process EAI undertook for renewable energy resources was excessively long and likely deterred many good projects from being bid in.

o As shown by the expedited SWEPCO procurement process for the Windcatcher project, Arkansas PSC’s approval process can be significantly faster to secure favorable tax credits.

V. Comment Topic: DSM and Demand Response Assumptions

Peter Dotson-Westphalen, CPower Energy Management for Advanced Energy Management Alliance

Other Stakeholders Joining This Comment: National Audubon Society and Sierra Club

* * *

The stakeholders appreciate EAI’s incorporation of feedback made in prior IRPs to

incorporate Demand Response (“DR”) and Demand Side Management (“DSM”) into the supply-

side for evaluation. However, there appears to be several shortcomings in the Aurora model, as

discussed in further detail within the “Modeling Deficiencies” section of the stakeholder

comments earlier in this document. Because of these modeling shortcomings, including capacity

selection based upon predetermined inputs of planned retirement dates and not looking at sub-

hourly time horizons, potential DSM was only selected in 2020 based upon the low case scenario

in the initial modeling, none of which came from any new DR.22 In the subsequent modeling

results, the model selected only between 9 to 14 MW of additional installed capacity coming

from DSM,23 all of which are lower than the lowest DSM portfolio additions used within the

initial modeling run. No further information was provided by EAI staff as to what changed from

the initial modeling runs that reduced the potential DSM that was selected in the second

modeling run, or how or why the DSM potential was reduced from the initial model runs.

22 http://www.entergy-arkansas.com/content/IRP/2018/June_6_Stakeholder_Meeting_Materials.pdf 23 http://www.entergy-arkansas.com/content/IRP/2018/Modeling_Update.pdf

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The stakeholders believe EAI’s cost effectiveness methodology is flawed because DR is

modeled solely at the MISO capacity auction price in the short term, which has remained

suppressed for some time. There was no clear delineation of when EAI transitioned to their long-

term methodology of modeling DR based upon the cost of building a new peaking resource, so

stakeholders cannot tell which cost-effectiveness methodology was used with each set of the

potential portfolios considered, and whether they aligned with the need for additional capacity

resources to be procured. At the initial stakeholder meeting on June 6, 2018, EAI presented

results from the Aurora Capacity Expansion Model and stated existing DR and incremental DSM

and DR is competing with all other supply-side resources.24 However, this model does not

consider comparing the cost-effectiveness of DR to existing generation resources that may be

impacted by higher future operating costs due to environmental compliance regulations and

market forces and may not be cost-effective in advance of their modeled retirement dates.

DR is found by many utilities to be a cost-effective resource,25 and the model’s failure to

select lower cost resources when it would be in the economic interest to do so appears to be a

significant flaw that is prevalent throughout EAI’s IRP. Several other utilities within MISO have

found DR to be a cost-effective resource within their IRPs. Consumers Energy in Michigan and

NIPSCO in Indiana both found that DR was the least-cost resource when compared to any

traditional supply-side generation resources within their recent modeling work. Ameren

Missouri, which was found to not have a need for new capacity until 2024, took an approach that

realized that the suppressed MISO capacity prices will not remain so over the longer term.

24 http://www.entergy-arkansas.com/content/IRP/2018/June_6_Stakeholder_Meeting_Materials.pdf 25 Advanced Energy Management Alliance (May 2018). Demand-Response Cost Effectiveness Case Studies. http://aem-alliance.org/download/121151/

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Ameren extended a rising cost curve for avoided capacity, energy, and T&D costs,26 and decided

that it could build out DR as a lower cost resource and then sell their excess generation capacity

from their existing resources into the MISO capacity market. Matt Michaels, Director of

Corporate Analysis for Ameren Missouri provided testimony to the value of DR and DSM,

stating, “[d]emand-side resources are generally more cost-effective than supply side-resources

and generate net benefits to an extent that most supply-side resources cannot.”27 The DSM

resource expansion portfolios developed by ICF International, Inc. (“ICF”) for EAI and included

in the Aurora Capacity Expansion Model reflect low total expansion opportunity for DR based

on scenarios, which consist of five Direct Load Control programs and one commercial Time-of-

Use program. The incremental DR from these six new programs ranges from a low of 25 MW up

to 100 MW.28 The stakeholders think these scenarios are not comprehensive of the total DR

opportunity available, especially considering EAI is forecasting significant growth in sales and

peak load through 2021 which it largely attributes to industrial customers that are typically good

candidates for DR. EAI noted in its presentation to stakeholders that none of these incremental

DR portfolios were selected in its model runs29 EAI has not provided any additional details on

the study assumptions ICF used to develop these incremental portfolios, and stakeholders have

26 Ameren Missouri. 2019-2024 MEEIA Plan – Appendix C - 2017 IRP Avoided Costs. [https://www.efis.psc.mo.gov/mpsc/commoncomponents/view_itemno_details.asp?caseno=EO-2018-0211&attach_id=2018020108] 27 Missouri Public Service Commission File No. EO-2018-0211. Surrebuttal Testimony of Matt Michels on Behalf of Union Electric Company d/b/a Ameren Missouri (September 17, 2018). [https://www.efis.psc.mo.gov/mpsc/commoncomponents/view_itemno_details.asp?caseno=EO-2018-0211&attach_id=2019003994] 28 http://www.entergy-arkansas.com/content/IRP/2018/June_6_Stakeholder_Meeting_Materials.pdf - 29 http://www.entergy-arkansas.com/content/IRP/2018/June_6_Stakeholder_Meeting_Materials.pdf

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not had the opportunity to review the assumptions to compare to other potential studies to

validate whether these assumptions allow the full DR potential to be captured.

EAI’s implementation of AMI within the service territory will open up additional DSM

program participation potential. EAI stated that they did not model any specific assumptions for

new rate or program designs that would capitalize on AMI infrastructure. EAI instead factored in

any load reductions attributed to increased AMI to the load forecast and are not assigned any

costs within the IRP.30 Stakeholders believe there is additional value through potential DSM/DR

programs that can be tapped into through AMI at a low cost that should be modeled on the

supply-side.

Finally, stakeholders are very concerned that EAI staff indicated that EAI may plan to

discontinue its existing DR programs based solely on low capacity clearing prices in the MISO

market and concluded that these programs are no longer cost effective to operate. As renewable

generation penetration increases, the need for more flexible and fast-responding resources will be

needed to help maintain reliability. It would be imprudent of EAI to disband their existing DR

programs, getting rid of approximately 230MW of LMR resources comprised of over 24,000

EAI customers that are helping to provide capacity and reliability during emergency conditions,

especially when EAI’s Total Resource Cost (TRC) for their entire portfolio of EE and DSM

programs have been cost effective in prior years and appear to be on track to remain cost

effective at a TRC of 1.8.31

30 http://www.entergy-arkansas.com/content/IRP/2018/Follow-Up_Materials_Set_3.pdf 31 http://www.entergy-arkansas.com/content/IRP/2018/June_6_Stakeholder_Meeting_Materials.pdf

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Recommendations

• EAI should seek to include T&D and avoided costs in its methodology for valuing its existing DR and DSM programs, and not solely rely on the MISO capacity value for assessing cost-effectiveness of these resources.

• EAI should model existing and potential DR and DSM against current generator operating costs, and not just against the cost of new entry of future generation.

• EAI should include Non-Wires Alternatives that can address localized needs that may reduce the need for T&D investment and increased capacity from traditional generation sources in their IRP modeling.

• EAI should model for additional potential DSM/DR program participation enabled by AMI being rolled out within their territory.

• EAI should not terminate their existing DR programs as these resources will be vital to help maintain a reliable grid today and in the future.

VI. Comment Topic: Energy Storage Assumptions


Other Stakeholders Joining This Comment: Advanced Energy Management Alliance, National Audubon Society, and Sierra Club

* * *

A. Energy Storage Data Assumptions

Lazard Associates’ estimated capital costs for various energy storage technologies

reaches as low as $1,152/kW in 2018. It is more difficult to assign a particular LCOE for energy

storage solutions; not only because of the variety of technology (batteries, fly wheels, etc.) and

rapidly declining prices, but because energy storage project finances are highly dependent on the

type of services being provided. For example, Lazard Associates notes that, “Although energy

storage developers/project owners often include Energy Arbitrage and Spinning/Non-Spinning

Reserves as sources of revenue for commissioned energy storage projects, Frequency

Regulation, Bill Management and Resource Adequacy are currently the predominant forms of

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realized sources of revenue.”32 For example, an energy storage project that predominantly

provides frequency regulation may appear to be exceptionally costly, on an LCOE basis,

compared to a traditional power plant; however, such a facility is providing a highly valued

service that may not be accurately reflected in current integrated resource planning processes,

models or specific utility markets. Energy storage is not simply a “cost adder” to renewable

energy to establish better capacity value.

The design of an energy storage project can also vary based on the specific services

desired; for example, a recent presentation by GTM Research showed four-hour and eight-hour

energy storage resources compared to peaking power resources. The researchers found that in

82% of planned future peaker plants would be at risk from eight-hour storage projects (e.g., 100

MW/800 MWh).33 Due to limitations in resource planning practices, LCOE or even capital costs

alone will not adequately assess the full benefits of energy storage. As energy storage resources

begin to be co-located with renewable energy resources, those energy storage technologies may

qualify for federal incentives, such as the investment tax credit. Energy storage pricing, as with

renewable energy, is anticipated to continue to considerably decline, while performance is

expected to improve, especially over the near-term.

32 Lazard Associates (November 2017). Levelized Cost of Storage Analysis, Version 3.0. [https://www.lazard.com/media/450338/lazard-levelized-cost-of-storage-version-30.pdf] 33 Ravi Manghani (March 2018). "Will Energy Storage Replace Peaker Plants?" GTM Research. [https://d3v6gwebjc7bm7.cloudfront.net/event/15/88/96/3/rt/1/documents/resourceList1519927946005/willenergystoragereplacepeakerplantswebinarslides1519927951937.pdf]

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Unsubsidized Energy Storage Capital Costs ($/kW)

Source: Lazard Associates 201734

1. Energy Storage Modeling

In February 2018, the Federal Energy Regulatory Commission (FERC) issued Order

Number 841 regarding energy storage. FERC stated, “In a November 2016 Notice of Proposed

Rulemaking (NOPR), the Commission noted that market rules designed for traditional generation

resources can create barriers to entry for emerging technologies such as electric storage

resources. Today’s final rule helps remove these barriers by requiring each regional grid operator

to revise its tariff to establish a participation model for electric storage resources that consist of

market rules that properly recognize the physical and operational characteristics of electric

storage resources.” FERC noted in its rule that, artificial “restriction on competition can reduce 34 Lazard Associates (November 2017). Levelized Cost of Storage Analysis, Version 3.0. [https://www.lazard.com/media/450338/lazard-levelized-cost-of-storage-version-30.pdf]

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the efficiency of the RTO/ISO markets, potentially leading an RTO/ISO to dispatch more

expensive resources to meet its system needs.”35 Even though RTO/ISO compliance filings are

due to FERC in early December, with tariff implementation due by December 2019, utilities

should strive to follow the spirit of FERC Order Number 841 in developing multiple modelling

capabilities, sensitivities and analyses around energy storage issues.36 In keeping with the

principles of FERC Order Number 841, it is recommended that multiple energy storage

configurations be evaluated (e.g., 2MW/2MWh, 2MW/4MWh, 2MW/8MWh, etc.), using sub-

hourly dispatch, with multiple revenue streams (e.g., capacity credit, energy, frequency/voltage

control, etc.), as stand-alone projects as well as coupled with generation resources (such as

renewable energy resources).

Models that use sub-hourly intervals can better quantify the value of both capacity and

flexibility benefits provided by advanced energy storage. By comparing flexibility benefits to the

cost of storage—thereby using a “net cost” analysis of capacity investment options—planners

can more accurately compare advanced energy storage with traditional capacity resources.

Analysis of models that look at system flexibility needs and risk management will be more likely

to reduce costs to ratepayers, including through use of storage. In addition to providing an LCOE

regarding energy storage options, it is also recommended that values also be provided in $/kW-

mo or $/kW-yr terms.

Behind the meter storage capabilities should be taken into consideration as well. As

35 Federal Energy Regulatory Commission (February 15, 2018). Electric Storage Participation in Markets Operated by Regional Transmission Organizations and Independent System Operators. [Docket Nos. RM16-23-000; AD16-20-000; Order No. 841]. https://www.ferc.gov/whats-new/comm-meet/2018/021518/E-1.pdf 36 Federal Energy Regulatory Commission (February 15, 2018). FERC issues final rule on electric storage participation in regional markets. [https://www.ferc.gov/media/news-releases/2018/2018-1/02-15-18-E-1.asp#.Wv3-1NOUv-Z]

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storage costs decline and customers begin to adopt storage technologies to serve needs and may

look to provide grid services as well, these resources should be accounted for within EAIs

modeling process.

Recommendations

• EAI should develop a “value stack” for energy storage resources incorporating energy, capacity, frequency response, black-start capability and other attributes available via energy storage devices.

• EAI should explain how it plans to incorporate lessons learned from FERC Order 841 on energy storage in future resource planning.

• EAI should procure significant energy storage assets to better evaluate storage costs and benefits.

VII. Comment Topic: Coal

Jordan Tinsley, Arkansas Electric Energy Consumers, Inc.

Other Stakeholders Joining This Comment: Arkansas Attorney General’s Office

* * *

In its 2015 Integrated Resource Plan, EAI acknowledged that its coal-fired power plants

should have a useful life of sixty years.37 At least two of the futures evaluated in the 2015 IRP

presumed the operation of EAI’s existing coal-fired power plants for a sixty-year useful life.38

Notably, however, EAI presumed (when evaluating those futures) that it would install costly

environmental controls at those plants as the result of a federal implementation plan (“FIP”) for

the Regional Haze Rule that will likely be superseded by a less onerous state implementation

plan (“SIP”) that does not require the installation of those environmental controls.39

37 See, e.g., EAI’s 2015 Integrated Resource Plan, APSC Docket No. 07-016-U, Doc. 49, p. 40. 38 Id. at 40-42. 39 Id.

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Although EAI acknowledges (at least implicitly) that the FIP promulgated by the EPA in

October 2016 will probably not survive ADEQ’s issuance of a new SIP,40 EAI has nonetheless

presumed early retirements of all its coal-fired capacity in the 2018 IRP process.41 Slide 6 of the

second set of Follow-Up Materials provided to IRP stakeholders clarified that EAI presumes it

will deactivate both White Bluff units by 2028; then, in 2030, it will deactivate Independence

Unit 1. Slide 7 of the second set of Follow-Up Materials states that White Bluff unit 1 is 38

years old, while unit 2 is 37 years old. It also states that Independence unit 1 is 35 years old.

Thus, if EAI retires White Bluff units 1 and 2 in 2028 as planned, EAI will be retiring those units

approximately twelve (12) to thirteen (13) years before the expiration of their sixty-year useful

lives. If EAI retires Independence unit 1 in 2030 as planned, EAI will be retiring that unit

approximately thirteen (13) years before the expiration of its sixty-year useful life.

Collectively, deactivation of those coal-fired power plants will retire over one thousand

(1000) megawatts of generating capacity. Of course, EAI plans to pass the cost of obtaining

replacement capacity for these early retirements on to its ratepayers. As noted in the comments

regarding early coal-plant deactivations AEEC included in EAI’s 2015 IRP stakeholder report,

EAI’s plans to retire its coal plants early will significantly raise electricity rates unnecessarily.42

40 See, e.g., slides 59-60 of the June 2018 Stakeholder Meeting Materials, which one can access using the following URL: http://entergy-arkansas.com/content/IRP/2018/June_6_Stakeholder_Meeting_Materials.pdf. 41 See slide 12 of the June 2018 Stakeholder Meeting Materials; see also slide 6 of the second set of Follow-Up Materials, which one can access using the following URL: http://entergy-arkansas.com/content/IRP/2018/Follow-Up_Materials_Set_2.pdf. 42 See EAI’s 2015 Integrated Resource Plan, APSC Docket No. 07-016-U, Doc. 49, p. 263-269.

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Further, EAI abdicates its fiduciary duties to its ratepayers under Arkansas law43 by divesting

them of approximately thirteen (13) years of cheap generating capacity without justification.

EAI and other parties attempt to justify the divestment of these assets from ratepayers by

emphasizing that these facilities are rarely dispatched in the status quo.44 The relatively low rate

of dispatch for these units, however, results primarily from low natural gas prices. Should

natural gas prices increase, the existence of this coal-fired capacity insulates ratepayers against

an electricity price spike. Further, since natural gas prices are inherently hard to predict,45

planning to retire these assets ten years in advance based upon uncertain gas price forecasts

seems imprudent. Further, as discussed below, the increased utilization of natural gas as a fuel

source for electricity generation continues to inject additional uncertainty into the natural gas

market, particularly with regard to extreme cold weather events.

If EAI proceeds with these planned retirements in 2028 and 2030 respectively, it will

remove coal as a fuel source from its fleet entirely. This eliminates valuable fuel diversity from

the EAI system. EAI’s primary resource planner strongly emphasized the value of fuel diversity

when justifying the acquisition of the Stuttgart Solar facility in 2015. He stated:

Diversity means utilizing a mix of generating technologies and fuel sources within the generation portfolio. A diverse generation portfolio mitigates risk by helping protect customers from fluctuations in the cost and availability of the fuel

43 See Acme Brick Co. v. Arkansas Public Service Commission, 227 Ark. 436, 299 S.W.2d 208 (1957) and City of El Dorado v. Arkansas Public Service Commission, 362 S.W.2d 680, 235 Ark. 812 (Ark., 1962). 44 For example, slide 7 of the second set of Follow-Up Materials states that White Bluff unit 1 has a capacity factor of sixty eight percent (68%), while the other two coal-fired units have capacity factors of approximately forty three percent (43%). 45 In APSC Docket No. 12-008-U, a witness for the Staff named Richard Hahn stated the following: “…the uncertainty in fuel prices should be considered. This factor is very difficult to assess either quantitatively or qualitatively. There is simply no way to know with any degree of certainty whether coal prices will remain lower than natural gas prices, or vice versa. It is true that historically natural gas prices have tended to be more volatile than coal prices.” Surrebuttal Testimony of Richard S. Hahn, APSC Docket No. 12-008-U, Doc. 145, p. 15 (emphasis added).

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needed to produce electricity. For example, a diverse generation portfolio protects customers from supply disruptions associated with particular fuel sources or delivery channels because alternative fuels are available within the portfolio. Similarly, fluctuations in the price of particular fuels are less likely to affect total supply cost. The effect of changes in the price of any one fuel is less significant because a diverse generation portfolio relies on a variety of fuels and resource types, the prices of which are not likely to move in perfect unison. Increases in the price of one fuel may be offset or mitigated by other fuels that exhibit declining or stable costs.46

Of course, Mr. Castleberry’s argument regarding fuel diversity has as much validity in

this context as it did in the context of adding some solar to EAI’s diverse portfolio. Notably, the

U.S. Energy Information Administration has noted that emphasizing natural gas as a fuel source

for electricity generation injects additional volatility into natural gas prices because of

fundamental economic realities concerning supply and demand.47 Therefore, the coal-fired

plants that EAI wants to divest from its portfolio thirteen years early actually provide ratepayers

with a valuable hedge against volatile natural gas prices.

Recent extreme cold weather events have demonstrated that concerns regarding gas

supply reliability are well-founded. For example, during extreme cold weather events, like the

polar vortex in 2014, gas plant curtailments may result from various factors. Problems with gas

transportation may also occur. NERC undertook an analysis of the polar vortex in the fall of

2014; it stated:

Increased reliance on natural gas during the polar vortex exposed the industry to various challenges with fuel supply and delivery. This increased reliance,

46 Direct Testimony of Kurtis W. Castleberry, APSC Docket No. 15-014-U, Doc. 16, p. 15-16 (emphasis added). 47 “Because there are limited short-term alternatives to natural gas as a fuel for heating and electricity generation during peak demand periods, changes in supply or demand over a short period may result in large price changes.” U.S. Energy Information Administration, Frequently Asked Questions, “What are the major factors affecting natural gas prices?,” https://www.eia.gov/tools/faqs/faq.php?id=43&t=8 (emphasis added).

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compounded by generation outages during the extreme conditions, increased the risks to the reliable operation of the BPS [bulk power system]. As the industry relies more on natural-gas-fired capacity to meet electricity needs, it is important to examine potential risks associated with increased dependence on a single fuel type. The extent of these concerns varies from Region to Region; however, they are most acute in areas where power generators rely on interruptible natural gas pipeline transportation. Unlike coal and fuel oil, natural gas is not typically stored on site. As a result, real‐time delivery of natural gas through a network of pipelines and bulk gas storage is critical to support electric generators. Natural gas is widely used outside the power sector, and the demand from other sectors—particularly coincident end-user gas peak demand during cold winter weather—critically affects gas providers’ ability to deliver interruptible transportation service in the power sector. Additionally, demand for natural gas is expected to grow in other sectors (e.g., transportation, exports, and manufacturing).48

Since the reliability of natural gas production, transportation, and generation in a world

where natural gas serves as the primary fuel source for electricity generation remains unknown,

it does not seem prudent for EAI to plan for the total elimination of coal as a fuel source in its

generation mix without further development and continued testing of the natural gas

infrastructure. As noted by NERC, coal plants do not suffer from some of the challenges posed

by natural gas-fired plants in extreme cold weather events. Additionally, FERC has recently

noted that natural gas storage inventories are at their lowest level since 2005, which could result

in increased natural gas prices as soon as this winter.49

Additionally, although EAI and other parties have emphasized the declining cost of

renewable generators as partial justification for the abandonment of the coal-fired plants, federal

48 North American Electric Reliability Corporation, Polar Vortex Review, September 2014, p. 17, available at the following link: https://www.nerc.com/pa/rrm/January%202014%20Polar%20Vortex%20Review/Polar_Vortex_Review_29_Sept_2014_Final.pdf. 49 Federal Energy Regulatory Commission, “2018-2019 Winter Energy Market Assessment,” available at the following link: https://ferc.gov/market-oversight/reports-analyses/mkt-views/2018/10-18-18-A-3-presented.pdf?csrt=66746001818521317.

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tax incentives driving those declining costs begin to expire soon,50 and the expiration of those tax

incentives may reverse the trend of declining costs.51 Therefore, EAI should not necessarily

presume that it can replace over one thousand megawatts of coal-fired generation with cheap

renewable plants.

In conclusion, EAI has reacted to the loosening of environmental regulations regarding

its coal plants with plans to accelerate their retirements. Said reaction, which is somewhat

counter-intuitive, creates concern that EAI merely hopes to retire those plants early so that it can

incur capital costs (and get a return on them) by building replacement capacity. Instead of

resource planning with its shareholders in mind, EAI should fulfill its fiduciary duties to its

ratepayers by examining the viability of operating its coal plants for the remainder of their sixty-

year useful lives.

Recommendation

• EAI should closely examine the economic viability of operating its coal-fired power plants for the remainder of their sixty-year useful lives.

VIII. Comment Topic: Energy Efficiency

Gary Moody, National Audubon Society

Other Stakeholders Joining This Comment: Advanced Energy Management Alliance, Arkansas Electric Energy Consumers, Inc., and Sierra Club

* * *

50 US Department of Energy, available at the following link: https://www.energy.gov/savings/renewable-electricity-production-tax-credit-ptc. 51 See U.S. Energy Information Administration, “Tax credits and solar tariffs affect timing of projected renewable power plant deployment,” May 15, 2018, available at the following link: https://www.eia.gov/todayinenergy/detail.php?id=36212; see also U.S. Department of Energy, 2017 Wind Technologies Market Report, p. xii, available at the following link: https://emp.lbl.gov/sites/default/files/2017_wind_technologies_market_report.pdf. ,

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A. EAI Treatment of EE in 2018 EAI IRP

The Stakeholder Group commends EAI for their leadership in EE program development

and deployment. Since the adoption of comprehensive energy efficiency targets in 2011, Entergy

Arkansas has been the leader among their peers in achieving efficiency savings. During the 2015,

EAI IRP process, stakeholders encouraged modeling EE as a resource. Stakeholders commend

EAI for working to implement that suggestion and offer the following comments as an

opportunity to further improve EE treatment in the IRP process moving forward.

The 2018 draft IRP as presented to the Stakeholder group considers four types of DSM:

Customer-sponsored DSM, Existing Utility-Sponsored DSM, Incremental Utility-Sponsored

DSM, and Interruptible Loads/DR. The draft IRP includes assumptions for the impacts of

Customer-Sponsored DSM and existing Utility-Sponsored DSM as modifiers to their Retail

Sales Forecast, while Incremental Utility sponsored DSM and Interruptible Loads/DR are

modeled as a supply side resource.

B. EE as a resource

The Stakeholders commend EAI for working with ICF to treat incremental Utility-

sponsored EE as a supply-side resource, and allowing it to compete dynamically in the model for

future utility investment against other capacity resources as recommended in the 2015 IRP

Stakeholder report.

Stakeholders note that one of the two available EE portfolio options was selected by the

model in all futures modeled at the earliest date available (2020). As EAI has noted that APSC

approval will be needed for these additional resources, we encourage EAI to begin that process

as soon as is practicable.

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The Stakeholder group would also encourage EAI to continue to refine and expand their

EE modeling process for future IRP processes.

C. Stakeholder Concerns

Despite the above noted improvement, the Stakeholder group does want to express one

concern related to EAI’s treatment of EE in the IRP draft. The estimate for Existing Utility –

Sponsored DSM is likely too conservative. With little explanation EAI chose to use 1.0% of

retail sales as the DSM proxy within the Sales and Load forecasts, despite significantly higher

achieved savings for recent years and the subsequent APSC order increasing targets to 1.2% of

annual sales. Planning on 1.0% savings despite actually achieving 1.57% savings in 2016, 1.49%

for 2017, and estimated savings of 1.8% for 2018 - drastically underestimates the likely impact

of EE on future load. At a minimum EAI should use 120% of the current EE Savings target as a

reasonable proxy as they have indicated their planning and budgets for the next 3 year plan will

be designed to achieve at least that level of cost-effective savings. Underestimating EE this

substantially will lead to over estimating future capacity needs and increased costs for

consumers.

IX. Comment Topic: Coal

Tony Mendoza, Sierra Club

Other Stakeholders Joining This Comment: Advanced Energy Management Alliance, National Audubon Society

* * *

Entergy Arkansas co-owns and operates two large coal-burning power plants, the two-

unit White Bluff plant near Redfield and the two-unit Independence plant near Newark. As

Entergy evaluates how and when to replace these plants, Sierra Club urges the company to rely

on “all-source” requests for proposals to determine the most-economical, least-polluting means

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of meeting customers’ power needs.

A. Entergy Arkansas’s coal plants are dirty.

Burning coal is the single most environmentally damaging means of producing

electricity. At a time when the UN Intergovernmental Panel on Climate Change has warned in

its October 2018 report that a climate crisis of inundated coastlines, intensifying droughts, food

shortages, and powerful storms is approaching as soon as 2040, coal remains the most carbon-

intensive means of producing electricity. White Bluff and Independence are by far the largest

single sources of carbon pollution in Arkansas. In 2017, White Bluff emitted 9,143,967 tons of

carbon and Independence emitted 7,989,772 tons, according to U.S. EPA data.

In addition, White Bluff and Independence are the top two sources of sulfur dioxide

(“SO2”) and nitrogen oxides (“NOx”) pollution in the state of Arkansas and are among the

largest in the United States. The four Independence and White Bluff units are the largest in the

United States that lack post-combustion controls for both NOx and SO2. According to U.S. EPA

data, White Bluff emitted 23,212 tons of SO2 in 2017 and Independence emitted 19,486 tons that

year, which made these plants the 9th and 15th largest sources of SO2 pollution in the entire

country. In 2017, White Bluff was the 7th largest source of NOx in the entire United States,

emitting 11,418 tons, and Independence was the 25th largest source in the country, spewing 8,694

tons of NOx. Both NOx and SO2 are harmful to human health.

These plants also produce vast quantities of coal combustion residuals (“CCRs”) that are

likely to contaminate groundwater for generations, directly on the banks of the Arkansas and

White rivers. Entergy Arkansas’s public reporting confirms that the CCRs at both plants are

likely contaminating the groundwater.

There is therefore a moral imperative for Entergy Arkansas to cease burning coal as soon

as possible. Entergy’s decision to model the retirement of White Bluff in 2028 and

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Independence in 2030 is a positive start in that direction.

B. The economics of Entergy Arkansas’s coal plants are deteriorating.

The economics of Entergy Arkansas coal have deteriorated in recent years, as shown in

their annual capacity factors. These plants simply do not operate as often as they did before

2014 as more-efficient, less-expensive generation plants dispatch more often in the MISO and

SPP energy markets. The lack of any post-combustion controls for NOx and SO2 and of closed-

loop ash handling systems, at both plants is also a significant risk of increased costs at both

plants.

Table 1: Annual Capacity Factors for Entergy Arkansas Coal Plants

2014 2015 2016 2017

Independence 74.64% 35.21% 52.18% 51.63%

1 75.6% 37.81% 52.13% 43.19%

2 73.68% 32.61% 52.22% 60.13%

White Bluff 73.41% 43.35% 39.58% 55.59%

1 75.5% 43.04% 34.34% 67.52%

2 71.25% 43.66% 44.79% 43.75%

Moreover, based on data reported by the MISO and SPP energy markets and by Entergy

Arkansas, Sierra Club calculated the approximate revenues each plant generated by producing

power in recent years. These estimated revenues were compared to the actual operation costs of

the power plants, based on data reported by the owners of the power plants. This comparison

can show if the power plants were able to cover their costs to operate by selling electricity into

the SPP and MISO markets.

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Table 2: Cash Flow of White Bluff and Independence

Since the start of 2015, the White Bluff plant is estimated to have generated $119 million

dollars of revenue from the SPP energy market, $447 million of revenue from the MISO energy

market, and $11 million from the MISO capacity market. However, the cost to operate the coal

plant has been in excess of $669 million, meaning the plant has accumulated $103 million in

losses that were covered by customers. Independence has similarly been uncompetitive. It is

estimated to have generated $177 million dollars of revenue from the SPP energy market, $416

million of revenue from the MISO energy market, and $9 million of revenue from the MISO

Capacity market. However, the cost to operate the coal plant has been in excess of $659 million,

meaning the plant has lost a cumulative $57 million.

White Bluff 2015 2016 2017 SPP Energy Revenues $37 $35 $47 MISO Energy Revenues $134 $125 $177 MISO Capacity Revenues

$8 $2 $1

Total Revenues $179 $162 $225 Fuel Costs ($167) ($161) ($226) Operation Costs ($15) ($15) ($14) Maintenance Costs ($26) ($20) ($25) Total Costs ($208) ($196) ($265) Net Earnings (Losses) ($29) ($34) ($40) Independence 2015 2016 2017 SPP Energy Revenues $44 $65 $68 MISO Energy Revenues $109 $149 $158 MISO Capacity Revenues

$7 $1 $1

Total Revenues $160 $215 $227 Fuel Costs ($160) ($198) ($206) Operation Costs ($13) ($9) ($11) Maintenance Costs ($21) ($19) ($22) Total Costs ($194) ($226) ($239) Net Earnings (Losses) ($34) ($11) ($12)

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Both SPP and MISO markets have a large excess of available power plant resources,

including access to low-cost wind and solar. This market reality means that Entergy Arkansas

and the owners of White Bluff and Independence have had, and will continue to have, access to

lower cost energy off the market rather than operating the two coal plants.

In fact, during the last three years the cost of energy from the White Bluff and

Independence plants has generally exceeded the MISO market energy price. The cost of energy

from the MISO energy market was $28.91—$31.34/MWh (nominal) in the 2015—2017 period.

The cost of energy from White Bluff was $32.37—$34.07/MWh (nominal) in the 2015—2017

period. The cost of energy from Independence was $29.33—$36.14/MWh (nominal) in the

2015—2017 period. Thus, on the energy side, Entergy clearly has an opportunity to save

customers money by shifting away from these coal-burning plants.

C. Entergy Arkansas’s coal plants support economic development in Wyoming.

Each year, Entergy Arkansas and the co-owners of White Bluff and Independence spend

hundreds of millions of dollars on out-of-state coal, almost exclusively sourced from Wyoming.

These costs are ultimately paid by electric customers in Arkansas, and provide an economic

boost to the Wyoming and Montana economies, and a corresponding drain on the Arkansas

economy via direct payments and the negative multiplier effect.

Recommendation

Sierra Club recommends that EAI issue an “all-source” requests for proposal (“RFP”)

modeled on the Xcel (2017) and NIPSCO (2018) RFPs to test the market for replacing the

energy and/or capacity provided by White Bluff and Independence sooner than 2028 and 2030.

If EAI ultimately determines that it will shut White Bluff and Independence in 2028 and 2030,

then EAI should use an all-source RFP ahead of those shutdowns to test the market for the most-

economical and least-polluting means of replacing these plants. Key attributes of such an RFP

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should include: i) requesting all solutions regardless of technology, including demand-side

options and storage, such that the RFP is truly “all source;” ii) defining a minimum total need of

a certain number MW for the portfolio of resources but without a cap, while also allowing

smaller resources to offer their solution as a piece of the total need; and iii) seeking bids for asset

purchases and purchase power agreements for new and existing resources. Sierra Club asks that

EAI provide an opportunity for stakeholders to comment on a draft RFP before it issued.

X. Comment Topic: Advanced Nuclear

Katie Niebaum, Arkansas Advanced Energy Association

Other Stakeholders Joining This Comment: None.

* * *

The Arkansas Advanced Energy Association (AAEA) encourages EAI to consider

advanced nuclear energy in its long-term resource planning. Advanced nuclear power

technologies are different in that they address many of the concerns that have limited the

deployment of commercial-scale conventional nuclear power generation. Some of the benefits of

advanced nuclear include:

• Zero emissions. Not just GHGs, but also other criteria pollutants such as NOx, SOx, PM, etc.

• High Capacity Factor. The U.S. nuclear fleet currently averages >92%. • Baseload. Nuclear generating facilities are reliable and dispatchable. • Small scale. Advanced nuclear systems are available in much smaller increments (e.g.,

50-300 MW) than conventional systems. • Small land area. Small physical footprints. • Short lead time. Compared to conventional nuclear technologies, advanced technologies

require less lead time for commercial deployment. • Improved waste management. Advanced nuclear technologies can address some of the

concerns associated with long-term management of spent nuclear fuel from conventional nuclear plants. In some cases, advanced nuclear systems actually use the spent fuel from conventional facilities as feedstock.

AAEA recognizes that many of the issues associated with conventional nuclear facilities

have created a climate of concern and distrust regarding nuclear technology. Nonetheless, the

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broad range of benefits noted above warrant serious consideration of advanced nuclear energy

for future power generation in Arkansas, particularly in light of EAI’s plans to decommission the

White Bluff, Independence, and Arkansas Nuclear One facilities. AAEA stands ready to work

with EAI to evaluate and, potentially, deploy advanced nuclear power generation technologies in

Arkansas during the longer-term horizon. Advanced nuclear energy could become a key

component of EAI’s strategy to replace baseload power while also reducing emissions.

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2018 eai integrated resource plan - entergy arkansas...october 31, 2018 ms. mary loos arkansas...

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